2018 electric retail rate filing - rhode island · 2018. 3. 12. · d/b/a national grid ripuc...

National Grid

2018 ELECTRIC RETAIL RATE FILING

Consisting of the Direct Testimony and Schedules of Adam S. Crary and Polina V. Demers

February 2018

Submitted to: Rhode Island Public Utilities Commission RIPUC Docket No. 4805

Submitted by:

Filing L

etter

40 Sylvan Road, Waltham, MA 02451 T: [email protected] www.nationalgrid.com

February 15, 2018

BY HAND DELIVERY AND ELECTRONIC MAIL

Luly E. Massaro, Commission Clerk Rhode Island Public Utilities Commission 89 Jefferson Boulevard Warwick, RI 02888

RE: Docket 4805 - 2018 Annual Retail Rate Filing Dear Ms. Massaro:

I have enclosed ten (10) copies of National Grid’s1 2018 Annual Retail Rate Filing. This filing consists of rate adjustments arising out of the reconciliation of the Company’s Standard Offer Service (SOS), SOS administrative costs, non-bypassable transition charge, transmission service, transmission-related uncollectible expense, renewable net metering credits, and long-term renewable energy contracts. The reconciliation period for the various costs in this filing is January 2017 through December 2017. The proposed rate adjustments are effective for usage on and after April 1, 2018. The Company’s filing includes the direct testimonies and schedules of Adam S. Crary and Polina V. Demers in support of the proposed rate changes. Please note that in accordance with the PUC’s Orders in Docket 4599 and Docket 4691, I have also enclosed the Excel files on a USB Flash Drive that include the Company’s working papers in support of the 2018 Annual Retail Rates Filing. These Excel files include a confidential file entitled “NECO_Recs_SOS_2017.div.puc.” Pursuant to PUC Rule 1.2(g) and R.I. Gen. Laws § 38-2-2(4)(B), the Company respectfully requests that the PUC treat the Excel file entitled, “NECO_Recs_SOS_2017.div.puc” as confidential because it contains commercially sensitive market information, the disclosure of which could affect the balance of wholesale markets as well as National Grid’s ability to negotiate competitive terms with its wholesale electric suppliers. This information is also the type of information that the PUC has historically recognized as proprietary information. The Company has, therefore, enclosed a motion for confidential treatment.

In summary, the Company requests approval of the following rates and adjustment factors:

(1) SOS Adjustment Factors for each SOS procurement group, which are designed to recover a net under-recovery of SOS expense for the reconciliation period;

1 The Narragansett Electric Company d/b/a National Grid (National Grid or Company).

Raquel J. Webster Senior Counsel

Luly E. Massaro, Commission Clerk Docket 4805 - 2018 Retail Rate Filing February 15, 2018 Page 2 of 3

(2) SOS Administrative Cost Factors for each SOS procurement group, which are designed to recover the projected SOS administrative expense for the period April 1, 2018 through March 31, 2019 and to refund the over-recovery of SOS administrative expense for the reconciliation period;

(3) an adjustment to the SOS base reconciliation and a corresponding adjustment that the

Company will make to its Revenue Decoupling Mechanism reconciliation to reflect the PUC’s decision in Docket No. 4556, effective July 1, 2015, which provides for the recovery or crediting of the unbilled SOS Billing Adjustment applicable to all delivery service customers;

(4) a base Non-Bypassable Transition Credit Factor (Transition Charge) of 0.083¢ per kWh

based on New England Power Company’s annual Contract Termination Charge (CTC) for 2018 to The Narragansett Electric Company, the former Blackstone Valley Electric Company, and the former Newport Electric Corporation;

(5) a Transition Charge Adjustment Credit Factor of 0.004¢ per kWh, which is the result of

an under-recovery of CTC expense during the reconciliation period; (6) base Transmission Service Charges based on an estimate of 2018 transmission expense

to be billed to the Company;

(7) Transmission Service Cost Adjustment Factors designed to: (1) refund the net over-recovery of transmission expense during the reconciliation period; (2) recover the projected transmission-related uncollectible expense allowance for the period April 1, 2018 through March 31, 2019; and (3) recover the net under-recovery of transmission-related uncollectible expense during the reconciliation period;

(8) a Net Metering Charge of 0.043¢ per kWh, which is designed to recover renewable net

metering credits paid to eligible net metering customers and the payments made to renewable Qualifying Facilities, which exceeded the net proceeds the Company received from ISO New England from the sale of the energy generated by the Qualifying Facilities for the reconciliation period; and

(9) a Long-Term Contracting (LTC) Reconciliation Factor of 0.068¢ per kWh, which is

designed to recover the under-recovery of expense during the reconciliation period. When added to the currently-effective LTC Recovery Factor of 0.519¢ per kWh for the period January 1, 2018 through June 30, 2018 (approved by the PUC in Docket No. 4673), the proposed LTC Reconciliation Factor results in a billable LTC Recovery Factor of 0.587¢ per kWh.

Luly E. Massaro, Commission Clerk Docket 4805 - 2018 Retail Rate Filing February 15, 2018 Page 3 of 3

The net effect of all rate changes proposed in this filing for a typical residential SOS customer using 500 kWh per month is an increase of $3.07, from $104.26 to $107.33, or 2.9%.

Thank you for your attention to this filing. If you have any questions, please contact me at 781-907-2121.

Very truly yours,

Raquel J. Webster Enclosures cc: John Bell, Division Al Mancini, Division Leo Wold, Esq.

STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS RHODE ISLAND PUBLIC UTILTITES COMMISSION

_______________________________________________ 2018 Annual Retail Rate Filing Docket No. 4805 __________________________________________________

NATIONAL GRID’S MOTION FOR PROTECTIVE TREATMENT

OF CONFIDENTIAL INFORMATION

National Grid1 respectfully requests that the Rhode Island Public Utilities Commission

(PUC) provide confidential treatment and grant protection from public disclosure certain

confidential, competitively sensitive, and proprietary information submitted in this proceeding,

as permitted by PUC Rule 1.2(g) and R.I. Gen. Laws § 38-2-2(4)(B). National Grid also

respectfully requests that, pending entry of that finding, the PUC preliminarily grant National

Grid’s request for confidential treatment pursuant to Rule 1.2 (g)(2).

I. BACKGROUND

On February 15, 2018, National Grid filed with the PUC its 2018 Annual Retail Rate

Filing, which includes rate adjustments arising out of the reconciliation of the Company’s

Standard Offer Service (SOS), SOS administrative costs, non-bypassable transition charge,

transmission service, transmission-related uncollectible expense, renewable net metering credits,

and long-term renewable energy contracts. In accordance with the PUC’s Orders in Docket

4599 and Docket 4691, the Company has provided the PUC and Rhode Island Division of Public

Utilities and Carriers (Division) with the Excel files (on USB Flash Drive) that include the

Company’s working papers in support of the 2018 Annual Retail Rates Filing. These Excel files

1 The Narragansett Electric Company d/b/a National Grid (National Grid or the Company).

2

include a file entitled, “NECO_Recs_SOS_2017.div.puc.” This file contains commercially

sensitive market information, the disclosure of which could affect the balance of wholesale

markets, as well as National Grid’s ability to negotiate competitive terms with its wholesale

electric suppliers. This information is also the type of information that the PUC has historically

recognized as proprietary information.

II. LEGAL STANDARD

The PUC’s Rule 1.2(g) provides that access to public records shall be granted in

accordance with the Access to Public Records Act (APRA), R.I. Gen. Laws §38-2-1 et seq.

Under the APRA, all documents and materials submitted in connection with the transaction of

official business by an agency is considered as a “public record,” unless the information

contained in such documents and materials falls within one of the exceptions specifically

identified in R.I. Gen. Laws §38-2-2(4). Therefore, to the extent that information provided to the

PUC falls within one of the designated exceptions to the public records law, the PUC has the

authority under the terms of the APRA to treat such information as confidential and to protect

that information from public disclosure.

In that regard, R.I. Gen. Laws § 38-2-2(4)(B) provides that the following types of records

shall not be deemed public:

Trade secrets and commercial or financial information obtained from a person, firm, or corporation which is of a privileged or confidential nature.

The Rhode Island Supreme Court has held that this confidential information exemption

applies where disclosure of information would likely either (1) impair the Government’s ability

to obtain necessary information in the future; or (2) cause substantial harm to the competitive

position of the person from whom the information was obtained. Providence Journal Company

v. Convention Center Authority, 774 A.2d 40 (R.I. 2001). The first prong of the test is satisfied

3

when information is voluntarily provided to the governmental agency and that information is of a

kind that would customarily not be released to the public by the person from whom it was

obtained. Providence Journal, 774 A.2d at 47. National Grid meets the second prong of this

test, which applies here.

III. BASIS FOR CONFIDENTIALITY

As discussed above, National Grid respectfully requests confidential and privileged

treatment of the excel file, entitled “NECO_Recs_SOS_2017.div.puc”. This file, which the

Company would not ordinarily disclose to the public, contains commercially sensitive market

information, the disclosure of which could affect the balance of wholesale markets, as well as

National Grid’s ability to negotiate competitive terms with its wholesale electric suppliers. This

information is also the type of information that the PUC has historically recognized as

proprietary information.

IV. CONCLUSION

Accordingly, the Company respectfully requests that the PUC grant protective treatment

to the excel file, entitled “NECO_Recs_SOS_2017.div.puc”.

4

WHEREFORE, for the foregoing reasons, the Company respectfully requests that the

PUC grant its Motion for Protective Treatment.

Respectfully submitted,

NATIONAL GRID

By its attorneys,

____________________________ Raquel J. Webster, RI Bar # 9064

National Grid 40 Sylvan Road Waltham, MA 02451 (781) 907-2121 Dated: February 15, 2018

T

estimony of

A

dam S. C

rary

THE NARRAGANSETT ELECTRIC COMPANY D/B/A NATIONAL GRID

RIPUC DOCKET NO. 4805 2018 RETAIL RATE FILING

WITNESS: ADAM S. CRARY

PRE-FILED DIRECT TESTIMONY

OF

ADAM S. CRARY



WITNESS: ADAM S. CRARY

Table of Contents

I. Introduction and Qualifications .......................................................................................... 1

II. Purpose of Testimony ......................................................................................................... 2

III. SOS Adjustment Factors and Reconciliation ...................................................................... 5

IV. Standard Offer Service Administrative Cost Adjustment Factors .................................... 10

V. Unbilled Standard Offer Service Billing Adjustment ....................................................... 14

VI. Transition Charge .............................................................................................................. 17

VII. Transmission Charges ....................................................................................................... 21

VIII. Net Metering Charge and Reconciliation of Renewable Net Metering Credits and

Payments to Qualifying Facilities with Renewable Generation ....................................... 32

IX. LTC Recovery Factor and Reconciliation ........................................................................ 36

X. Typical Bills ...................................................................................................................... 46

XI. Summary of Retail Delivery Rates ................................................................................... 46

XII. Conclusion ........................................................................................................................ 47



WITNESS: ADAM S. CRARY PAGE 1 OF 47

I. Introduction and Qualifications 1

Q. Please state your full name and business address. 2

A. My name is Adam S. Crary, and my business address is 40 Sylvan Road, Waltham, 3

Massachusetts 02451. 4

5

Q. Please state your position. 6

A. I am a Senior Analyst for Electric Pricing, New England in the Regulation and Pricing 7

Department of National Grid USA Service Company, Inc. This department provides 8

rate-related support to The Narragansett Electric Company d/b/a National Grid (National 9

Grid or Company). 10

11

Q. Please describe your educational background and training. 12

A. In 1995, I graduated from Berklee College of Music in Boston, MA with a Bachelor of 13

Music degree. 14

15

Q. Please describe your professional experience. 16

A. For approximately eight years between 2000 and 2014, I was employed by Computer 17

Sciences Corporation as a Pricing Analyst for their Managed Hosting and Cloud 18

Computing business divisions, respectively. I began my employment as a Senior Pricing 19

Analyst with National Grid in June 2014. 20

21




Q. Have you previously testified before Rhode Island Public Utilities Commission 1

(PUC)? 2

A. Yes. 3

4

II. Purpose of Testimony 5

Q. What is the purpose of the Company’s filing? 6

A. In this filing, the Company is requesting PUC approval of the following: 7

(1) Standard Offer Service (SOS) Adjustment Factors for each SOS class of service 8

designed to recover a net under-recovery of SOS expense for the 12-month period 9

ending December 31, 2017; 10

(2) SOS Administrative Cost Factors for each SOS class of service designed to recover 11

the projected SOS administrative expense for the period April 1, 2018 through March 12

31, 2019 and to credit or recover the over-recovery or under-recovery of SOS 13

administrative expense for the 12-month period ending December 31, 2017; 14

(3) an adjustment to the SOS base reconciliation and a corresponding adjustment to the 15

Revenue Decoupling Mechanism to reflect the PUC’s decision in RIPUC Docket No. 16

4556 that, as of July 1, 2015, the unbilled SOS Billing Adjustment must be recovered 17

from or credited to all delivery service customers; 18

(4) a base Non-Bypassable Transition Charge (Transition Charge) that is proposed as a 19

credit of 0.083¢ per kWh based upon New England Power Company’s (NEP) annual 20

Contract Termination Charge (CTC) for 2018 to Narragansett Electric Company, the 21




former Blackstone Valley Electric Company (BVE), and the former Newport Electric 1

Corporation (Newport); 2

(5) a Transition Charge Adjustment Factor that is proposed as a credit of 0.004¢ per kWh 3

resulting from an over-recovery of CTC expense during the 12-month period ending 4

December 31, 2017; 5

(6) base Transmission Service Charges based upon an estimate of 2018 transmission 6

expense to be billed to the Company; 7

(7) Transmission Service Cost Adjustment Factors (TSCAF) designed to (1) refund the 8

net over-recovery of transmission expense incurred during the 12-month period 9

ending December 31, 2017; and (2) recover the projected transmission-related 10

uncollectible expense allowance for the period April 1, 2018 through March 31, 2019 11

and the under-recovery of transmission-related uncollectible expense incurred during 12

the 12-month period ending December 31, 2017; 13

(8) a Net Metering Charge of 0.043¢ per kWh, which is designed to recover Renewable 14

Net Metering Credits paid to eligible net metering customers and the payments made 15

to renewable Qualifying Facilities that are in excess of payments that the Company 16

receives from ISO New England (ISO-NE) from the sale of the energy generated by 17

the Qualifying Facilities for the 12-month period ending December 31, 2017; and 18

(9) a Long-Term Contracting for Renewable Energy Recovery Factor (LTC Recovery 19

Factor) of 0.587¢ per kWh, which includes the proposed LTC Reconciliation Factor 20

of 0.068¢ per kWh, designed to recover the under-recovery of expense during the 12-21




month period ending December 31, 2017, and the currently-effective LTC Recovery 1

Factor of 0.519¢ per kWh for the period January 1, 2018 through June 30, 2018, 2

approved by the PUC in RIPUC Docket No. 4775 at its December 20, 2017 open 3

meeting. 4

In support of the above requests, the Company is presenting its annual reconciliations for 5

SOS, SOS administrative costs, the non-bypassable transition charge, the transmission 6

service charge, the transmission-related uncollectible expense, the Net Metering charge, 7

and the LTC Recovery Factor. The reconciliation period for the various costs in this 8

filing is January 1, 2017 through December 31, 2017. 9

10

The net effect of all rate changes proposed in this filing for a typical residential SOS 11

customer using 500 kWh per month is an increase of $3.07 from $104.26 to $107.33, or 12

approximately 2.9%. Schedule ASC-1 presents a summary of the proposed rate changes. 13

The Company is proposing that the rate and tariff changes identified above be effective 14

for usage on and after April 1, 2018. 15

16

Q. Is the Company requesting approval from the PUC for the Renewable Energy 17

Standard (RES) Charge in this filing? 18

A. No. The Company will submit its proposed 2018 RES Charge and reconciliation in a 19

separate filing prior to March 1, 2018. 20

21




III. SOS Adjustment Factors and Reconciliation 1

SOS Adjustment Factors 2

Q. Is the Company proposing SOS Adjustment Factors for April 1, 2018? 3

A. Yes. The Company is proposing separate SOS Adjustment Factors for the Residential, 4

Commercial, and Industrial Customer Groups, which are designed to recover from or 5

credit customers, as appropriate, a net under-recovery of approximately $4.1 million 6

incurred during the twelve-month period ending December 2017. For billing purposes, 7

the Company will include the SOS Adjustment Factors with the SOS Charge on 8

customers’ bills. 9

10

Q. Please describe the Company’s SOS customer classes. 11

A. Pursuant to its Tariff for Standard Offer Service, RIPUC No. 2155, the Company 12

provides SOS to three separate SOS procurement groups: the Residential Group, the 13

Commercial Group, and the Industrial Group. The Residential Group consists of 14

customers taking service on Basic Residential Rate A-16 and Low Income Rate A-60. 15

The Commercial Group consists of customers receiving service pursuant to Small C&I 16

Rate C-06, General C&I Rate G-02, and outdoor lighting Rates S-05, S-06, S-10, 17

and S-14. Finally, the Industrial Group consists of the Company’s large C&I classes, 18

Large Demand Rate G-32, Optional Large Demand Rate G-62, Backup Service Rates 19

20




B-32 and B-62, and Electric Propulsion Rate X-01. The Company procures and prices 1

SOS separately for each of these procurement groups and tracks revenue and expenses 2

separately for each group. 3

4

SOS Reconciliation 5

Q. Please describe the Company’s SOS reconciliation for the period January 2017 6

through December 2017. 7

A. This reconciliation is included as Schedule ASC-2. Page 1 of Schedule ASC-2 reflects a 8

total under-recovery of approximately $4.1 million for the period January 2017 through 9

December 2017. 10

11

Q. Please describe the SOS reconciliation process in more detail. 12

A. The Company is required to reconcile SOS revenues and expenses in accordance with the 13

SOS Adjustment Provision, RIPUC No. 2157. This provision requires the Company to 14

reconcile, on an annual basis, its total cost of purchased power for SOS supply against its 15

total SOS revenue, and to refund the excess to or recover the deficiency from customers 16

through a rate recovery/refund methodology approved by the PUC at the time the 17

Company files its annual reconciliation. 18

19

Total revenue is generated from charges billed to SOS customers through the SOS rates 20

for the applicable reconciliation period. Since the Company procures and prices SOS 21




separately for the Residential Group, the Commercial Group, and the Industrial Group, 1

the Company has performed separate reconciliations for each group. The SOS 2

reconciliations for each procurement group and a total Company consolidated 3

reconciliation are presented in Schedule ASC-2. 4

5

Q. Please describe the adjustment shown in the SOS reconciliation, Schedule ASC-2, 6

Line (3). 7

A. The adjustment of $1,175,565 shown on Line (3) of Pages 1 through 4 of the 8

reconciliation reflects the remaining balance of the 2015 net over-recovery of SOS 9

expense for the period January 1, 2015 through December 31, 2015 that was recovered 10

from or credited to customers during the period April 1, 2016 through March 31, 2017. 11

12


Line (4). 14

A. The adjustment of $411,791 shown on Line (4) of pages 1 through 3 reflects a 15

reallocation of Spot Market purchase resettlement amounts, plus accumulated interest, 16

through ISO-New England by the Company prior to January 2017 that had previously 17

been incorrectly reflected in the Company’s annual retail rate filings. The Company had 18

incorrectly reflected energy sales for certain Long Term Contracts, Qualifying Facilities, 19

or Net Metered facilities, as Spot Market energy resettlement purchases in the SOS 20

reconciliation rather than in the Long Term Contracting for Renewable Energy Recovery 21




(LTCRER) and Net Metering reconciliations. As a result, the Company overstated the 1

total Spot Market procurement amounts prior to January 2017 from ISO-NE for 2

Residential and Commercial Standard Offer Service customers and understated the costs 3

in the LTCRER and Net Metering reconciliations. The purpose of the adjustment is to 4

reflect the correct amount of purchase expense to Residential and Commercial SOS 5

customers. The Company is making offsetting adjustments to the LTCRER and Net 6

Metering reconciliations. 7

8


Line (5). 10

A. The adjustment of ($137,654) shown on Line (5) of Pages 1 through 3 of the 11

reconciliation reflects the unbilled SOS Billing Adjustments for the period January 1, 12

2017 through December 31, 2017. This adjustment will be discussed in further detail 13

later in my testimony. 14

15

Q. Has the Company included a schedule showing the final balance of the 2015 net 16

over-recovery incurred during the period January 2015 through December 2015? 17

A. Yes. Pages 7-9, Section 1, of Schedule ASC-2 present the final status of each 18

procurement group’s over/under-recovery incurred during January 2015 through 19

December 2015. The beginning net over-recovery balance for the three procurement 20

groups of $9,987,818 was reflected in approved respective SOS Adjustment Factors in 21




Docket No. 4599, effective April 1, 2016 through March 31, 2017. As shown on 1

Schedule ASC-2, Page 7, 8, and 9, the remaining net balance due to refund to or recover 2

from SOS customers was $1,175,565 as of March 31, 2017. This remaining balance is 3

included as an adjustment to the current base reconciliation on Schedule ASC-2, Line (3). 4

5

Q. Has the Company included a status of the recovery of the 2016 SOS over-recovery 6

incurred during the period January 2016 through December 2016 that the 7

Company is crediting/recovering during the 12 months ending March 31, 2018? 8

A. Yes. Pages 7-9, Section 2, of Schedule ASC-2 present the status of each procurement 9

group’s over-recovery incurred during the January 2016 through December 2016 10

reconciliation period. The PUC approved the SOS Adjustment Factors based upon the 11

combined beginning over-recovery balance of $16,214,984 in Docket No. 4691. All 12

over-recovery amounts are being credited through the SOS Adjustment Factors 13

implemented on April 1, 2017. The Company will continue to apply the currently 14

effective adjustment factors through March 31, 2018. Any balance remaining at that 15

time, positive or negative, will be reflected in next year’s SOS reconciliation as an 16

adjustment. 17

18

Calculation of the SOS Adjustment Factors 19

Q. How are the SOS Adjustment Factors developed? 20

A. The proposed SOS Adjustment Factors are developed in Schedule ASC-3. The SOS 21




Adjustment Factors are calculated by dividing the ending balance of the SOS 1

reconciliation for each procurement group plus estimated interest during the period 2

during which the factors will be in effect by the forecasted SOS kWh deliveries for each 3

procurement group during the period April 2018 through March 2019. 4

5

IV. Standard Offer Service Administrative Cost Factors 6

Q. Please describe the SOS Administrative Cost Factors. 7

A. Pursuant to the Company’s Standard Offer Adjustment Provision, the SOS 8

Administrative Cost Factors, which are applicable to customers receiving SOS, recover 9

administrative costs associated with arranging, administering, and providing SOS. In 10

accordance with the Standard Offer Adjustment Provision, on an annual basis, the 11

Company reconciles its administrative cost of providing SOS with its SOS revenue 12

associated with the recovery of administrative costs and the excess or deficiency, 13

including interest at the interest rate paid on customer deposits, is credited to, or 14

recovered from, SOS customers in the subsequent year’s SOS Administrative Cost 15

Factors. 16

17

Q. What costs are included for recovery in the SOS Administrative Cost Factors? 18

A. The Company is allowed to recover administrative costs associated with the following: 19

working capital; complying with the requirements of Renewable Energy Standard 20

established in R.I. Gen. Laws § 39-26-1; creating the environmental disclosure label; the 21




costs associated with the New England Power Pool (NEPOOL) Generation Information 1

System (GIS) attributable to SOS; procurement of SOS, including requests for bids, 2

contract negotiation, and execution and contract administration; notifying SOS customers 3

of the rates for SOS; updating rate changes in the Company’s billing system; and an 4

allowance for SOS-related uncollectible expense associated with amounts billed through 5

SOS rates and the SOS Administrative Cost Factors at the uncollectible rate approved by 6

the PUC.1 7

8

Q. Has the Company proposed SOS Administrative Cost Factors to be effective 9

April 1, 2018? 10

A. Yes. The proposed factors are developed in Schedule ASC-4. 11

12

Q. How are the proposed factors calculated? 13

A. Pursuant to the Standard Offer Adjustment Provision, the proposed SOS Administrative 14

Cost Factors are designed to collect the following: (1) an allowance for SOS-related 15

uncollectible expense based upon estimated SOS base revenue, estimated SOS 16

Adjustment Factor revenue, and estimated RES revenue associated with each 17

procurement group for the upcoming year; (2) administrative costs associated with 18

arranging SOS for the upcoming year, and; (3) any over- or under-recoveries of SOS 19

administrative costs from the prior year. 20

1 As approved in the Company’s general rate case in Docket No. 4323, the current allowed uncollectible rate of 1.25% became effective on February 1, 2013.




Q. How does the Company estimate the SOS revenue and associated uncollectible 1

expense for the period April 1, 2018 through March 31, 2019? 2

A. Uncollectible expense is based upon estimated SOS base revenue, SOS Adjustment 3

Factor revenue, and RES revenue for the period April 1, 2018 through March 31, 2019. 4

The revenue is calculated as each procurement group’s estimated SOS kWh deliveries 5

for the 12 months ending March 31, 2019, multiplied by the sum of the SOS base rates 6

proposed in the January 18, 2018 SOS filing in Docket No. 4692, the current RES rate, 7

and the proposed SOS Adjustment Factors. The estimated revenue is then multiplied by 8

the uncollectible rate to determine the estimated commodity-related uncollectible 9

expense. Estimated commodity-related uncollectible expense is shown on Line (1) of 10

Schedule ASC-4, Page 1. The details of this estimate are included on Page 2 of Schedule 11

ASC-4. 12

13

Q. How does the Company estimate other SOS administrative expenses? 14

A. SOS administrative expense is categorized into three components: GIS costs, other 15

administrative costs, and cash working capital. The estimated GIS and other 16

administrative costs are based upon the actual expense incurred in 2017 and are allocated 17

to each procurement group based on each procurement group’s percentage share of SOS 18

expense during the 12-month period ending December 31, 2017. The Company bases its 19

2018 SOS cash working capital estimate on the prior year’s actual SOS cash working 20

capital cost and allocates the estimate to each procurement group based upon each 21




group’s actual SOS revenue as a percentage of total SOS revenue. However, since the 1

corporate federal income tax rate was reduced from 35 percent to 21 percent effective 2

January 1, 2018, for purposes of estimating 2018 SOS cash working capital cost, the 3

Company recalculated the 2017 SOS cash working capital cost using the 21 percent 4

federal income tax rate that went into effect January 1, 2018. The total estimated SOS 5

administrative expense for 2018 is shown on Line (3) of Schedule ASC-4, Page 1. 6

7

SOS Administrative Cost Reconciliation 8

Q. Did the Company prepare a reconciliation of the recovery of actual SOS 9

administrative costs for the period ending December 31, 2017? 10

A. Yes. The SOS administrative cost reconciliation for the period January 1, 2017 through 11

December 31, 2017 is presented in Schedule ASC-5. Consistent with the reconciliation 12

of base SOS costs, the Company has prepared separate reconciliations for the Residential 13

Group, the Commercial Group, and the Industrial Group. The reconciliations on Pages 2, 14

3, and 4 of Schedule ASC-5 present the over/under-recovered balances, including 15

interest, during the reconciliation period, of an over-recovery of $229,655 for the 16

Residential Group, an over-recovery of $37,235 for the Commercial Group, and an 17

under-recovery of $71,824 for the Industrial Group. 18

19




Q. Please describe the amounts on Pages 4, 5, and 6, Column (h), labeled Cash 1

Working Capital. 2

A. The amounts on Schedule ASC-5, Pages 6, 7, and 8, Column (h) labeled Cash Working 3

Capital, are the commodity-related working capital requirements during 2017 for each 4

procurement group. The Cash Working Capital calculation is presented in Schedule 5

ASC-6. 6

7

Q. How is the Company proposing to credit or recover each procurement group’s 8

over/under-recovery of SOS administrative costs? 9

A. The Company is proposing to credit/ recover each procurement group’s over/under-10

recovery of SOS administrative costs through group-specific adjustment factors. The 11

proposed factors are developed in Schedule ASC-7. Each procurement group’s factor is 12

developed by dividing the procurement group’s over/under-recovery, including interest 13

during the recovery period, by the procurement group’s forecasted SOS kWh deliveries. 14

These factors are included in the proposed SOS Administrative Cost Factors, as shown in 15

Schedule ASC-4, Page 1, Line (6). 16

17

V. Unbilled Standard Offer Service Billing Adjustment 18

Q. Please describe Schedule ASC-8. 19

A. Schedule ASC-8, Page 1 identifies the monthly unbilled SOS Billing Adjustments by 20

21




SOS procurement group. These amounts form the basis for an adjustment to the SOS 1

reconciliation for the same period. 2

3

Q. Why is the Company proposing this adjustment to the SOS reconciliation balance? 4

A. In Docket No. 4556, the PUC approved the termination of the SOS Billing Adjustment, 5

effective July 1, 2015. The SOS Billing Adjustment was a one-time billing adjustment 6

applied to Residential and Commercial customers’ bills when they switched to a 7

competitive energy supplier from SOS and were billed a fixed SOS rate (fixed SOS rates 8

are an option only for Commercial customers – all Residential customers are billed a 9

fixed SOS rate). This adjustment accounted for the difference between the fixed SOS 10

rate for a SOS pricing period and the monthly contract prices at which the Company 11

procured SOS from its SOS suppliers. This one-time adjustment could result in either a 12

credit or charge to the customer. 13

14

The PUC further directed the Company to track the unbilled SOS Billing Adjustments 15

beginning July 1, 2015 through the end of the reconciliation period and to recover from 16

or credit to all retail delivery service customers the net amount of the adjustments. 17

18

Q. How is the adjustment applied to the SOS base reconciliation? 19

A. As required by the SOS Adjustment Provision, the Company must apply a Revenue 20

Adjustment (defined as an increase to SOS revenue in the SOS reconciliation) if the 21




variable rate billing less fixed rate billing is positive (i.e., the Company paid more to SOS 1

suppliers than it billed SOS customers), and a decrease to SOS revenue in the SOS 2

reconciliation if the variable rate billing less the fixed rate billing is negative (i.e., the 3

Company paid less to SOS suppliers than it billed SOS customers). This adjustment to 4

SOS revenue in the SOS reconciliation results in the SOS revenue being at a level it 5

would have been had the Company continued to bill these SOS Billing Adjustments. In 6

this way, SOS customers are not harmed by the termination of the SOS Billing 7

Adjustment. In addition, they also do not benefit from the termination of the adjustment. 8

9

Q. What do the amounts in Schedule ASC-8 indicate? 10

A. Schedule ASC-8 quantifies the total net unbilled SOS Billing Adjustments for 2017 for 11

the Residential and Commercial Groups, which was a net credit of $137,654. This 12

amount is shown as an adjustment to the Residential and Commercial customer group 13

SOS base reconciliations in Schedule ASC-2, pages 2 and 3. The net amount of the 14

unbilled SOS Billing Adjustment is negative, or a credit of $137,654, meaning that, in the 15

aggregate, for all of the SOS customers who are billed a fixed SOS rate and who left SOS 16

to take their electric supply from a non-regulated power producer, the Company paid less 17

for their SOS supply than what it billed those customers. Therefore, the Company is 18

adjusting the Residential and Commercial SOS reconciliations, that, effectively, reduces 19

the revenue in each reconciliation to match SOS costs. 20

21




Q. How does the Company propose to provide the value to customers that it has 1

removed from the SOS reconciliation as a result of reducing SOS revenue in the 2

amount of the 2017 net SOS Billing Adjustment? 3

A. The Company is proposing to reflect the net credit (i.e., the revenue billed in excess of 4

the cost to provide SOS) of the SOS Billing Adjustment as an adjusting credit to the 5

Revenue Decoupling Mechanism (RDM) reconciliation, which will be filed by May 15, 6

2018. The RDM Adjustment Factor is a uniform per kWh factor applicable to all retail 7

delivery service customers. Therefore, all customers will receive a portion of the net 8

SOS Billing Adjustment credit through application of the RDM Adjustment Factor. 9

10

VI. Transition Charge 11

Base Transition Charge 12

Q. Please describe the Company’s Transition Charge. 13

A. The purpose of the Transition Charge is to recover from all retail delivery service 14

customers the CTC billed to the Company by NEP, including charges in effect under the 15

former Montaup Electric Company’s CTC. In addition, the Company reconciles the 16

revenue it bills its customers through the Transition Charge against the CTC billed to it 17

by NEP and can propose to implement a Transition Charge adjustment factor to credit 18

customers for an over-recovery of CTC costs or recover an under-recovery of CTC costs. 19

20




Q. What is the Company’s proposal in this filing? 1

A. In this filing, the Company is proposing a Transition Charge Credit for the 12-month 2

period ending March 31, 2019 of 0.087¢ per kWh, as shown in Schedule ASC-9, Page 1. 3

The credit represents (1) the weighted average CTC credit factor of 0.083¢ per kWh and 4

(2) a Transition Charge Adjustment Factor credit of 0.004¢ per kWh designed to credit 5

all customers the over-recovery of CTC costs for the period January 2017 through 6

December 2017. 7

8

Q. How is the weighted average CTC calculated? 9

A. Schedule ASC-9, Page 2 shows the calculation of the weighted average CTC for 2018. 10

The individual CTCs and estimated GWhs for Narragansett Electric, BVE, and Newport, 11

shown in Section 1 of Page 2, are based upon NEP’s 2018 CTC. The individual company 12

CTCs determined in Section 1 are aggregated in Section 2 and divided by the total GWh 13

deliveries to arrive at a weighted average credit CTC of 0.083¢ per kWh. This is the 14

basis for the proposed base Transition Charge credit factor of 0.083¢ per kWh effective 15

April 1, 2018. 16

17

Transition Charge Reconciliation 18

Q. Please describe how the Company reconciles its Transition Charge. 19

A. The Company reconciles Transition Charge revenue and CTC expense in accordance 20

with its Non-Bypassable Transition Charge Adjustment Provision. The excess or 21




deficiency must be credited to or recovered from customers with interest accruing at the 1

rate in effect for customer deposits. The reconciliation covers the period January 2017 2

through December 2017, as reflected in Schedule ASC-10. Page 1 of Schedule ASC-10 3

presents the reconciliation. 4

5

Q. What is the total Company Transition Charge reconciliation balance for the 12 6

months ending December 31, 2017? 7

A. The balance for the period January 2017 through December 2017, shown in Schedule 8

ASC-10, Page 1, reflects an over-recovery of approximately $353,000. 9

10

Q. What is shown in Column (i) of Page 1, labeled “Adjustments”? 11

A. Column (i), Page 1, contains a $159,178 adjustment in the month of April 2017, which 12

represents the final balance of the over-recovery incurred during the period January 2015 13

through December 2015 that has been credited to customers during April 2016 through 14

March 2017, as shown on Schedule ASC-10, Page 2, Section 1, and described below. 15

16

Q. How is the Company proposing to reflect the over-recovery for the period January 17

2017 through December 2017 in rates? 18

A. As previously noted, the Company is proposing to add to the proposed base Transition 19

Charge credit factor of 0.083¢ per kWh, calculated on Schedule ASC-9, Page 2, the 20

proposed Transition Charge Adjustment Factor credit of 0.004¢ per kWh, as calculated in 21




Schedule ASC-10, Page 3. The Transition Charge over-recovery balance, including 1

estimated interest during the recovery period, is divided by the forecasted kWh deliveries 2

for the period April 1, 2018 through March 31, 2019, resulting in a credit of 0.004¢ per 3

kWh. This credit, when added to the base Transition Charge credit factor of 0.083¢ per 4

kWh, produces a Transition Charge credit factor of 0.087¢ per kWh, as shown on Line 5

(3), Page 1 of Schedule ASC-9. 6

7

Q. What does Page 2 of Schedule ASC-10 reflect? 8

A. Page 2, Section 1 of Schedule ASC-10 presents the final balance associated with the 9

over-recovery incurred during the period January 2015 through December 2015 that was 10

credited to customers during the 12-month period ending March 31, 2017. Page 2 of 11

Schedule ASC-10 shows that, as of March 31, 2017, there was a remaining balance owed 12

to customers of $159,178. This ending balance is included in the base Transition Charge 13

reconciliation as an adjustment in the month of April 2017, as shown on Page 1 of 14

Schedule ASC-10. 15

16

Page 2, Section 2 of Schedule ASC-10 also presents the status of the refund associated 17

with the over-recovery of CTC expense incurred during the period January 2016 through 18

December 2016 that is being credited to customers during the 12-month period ending 19

March 31, 2018. Page 2, Section 2, of Schedule ASC-10 shows that as of January 31, 20

2018, there remains a balance owed to customers of $847,609. The Company will 21




continue to credit the over-recovery to customers through March 31, 2018, at which 1

point, the remaining balance, positive or negative, will be reflected in next year’s base 2

Transition Charge reconciliation as an adjustment in the month of April 2018. 3

4

VII. Transmission Charges 5

Transmission Charges and Reconciliation 6

Q. Please describe the Company’s Transmission Service Cost Adjustment Provision 7

(TSCAP). 8

A. The Company recovers its transmission-related expenses pursuant to the TSCAP, RIPUC 9

No. 2115, which allows the Company to recover costs billed to it by ISO-NE, NEP, and 10

any other transmission service provider that is authorized to bill the Company directly for 11

transmission services. In addition, the provision allows for the recovery of an allowance 12

for transmission-related uncollectible expense. 13

14

Transmission charges are determined annually based upon a forecast of transmission 15

expense for the upcoming year and a transmission adjustment factor which is designed to 16

recover from or credit to customers under- or over-recoveries of expense from the prior 17

year. 18

19

Q. Has the Company prepared a forecast of transmission costs for 2018? 20

A. Yes, it has. This forecast is included in the testimony and schedules of Polina V. Demers, 21




who explains the forecast and how it was derived. The transmission forecast for 2018 is 1

approximately $208.1 million, a decrease of approximately $4.6 million from the 2017 2

forecast. 3

4

Q. How does the Company propose to recover the $208 million of forecasted 5

transmission expense for 2018? 6

A. The Company is proposing to recover the $208.1 million of 2018 estimated expense 7

through class specific base transmission demand and energy charges. 8

9

Base Transmission Charges 10

Q. Please describe the design of the Company’s proposed base transmission charges. 11

A. Schedule ASC-11 shows the design of the proposed base transmission charges. The first 12

step in designing the base transmission charges is to allocate the forecasted transmission 13

expense to each rate class. The total estimated 2018 transmission expense is allocated to 14

each class based on a coincident peak demand2 allocation factor. 15

16

Q. How is the coincident peak allocation factor developed? 17

A. The allocation factor is developed from rate class weighted average load factors that were 18

developed from coincident peak data for the years ending 2008 and 2011, as described 19

below. The Company used a similar methodology in its most recent general rate case in 20

Docket No. 4323 in the development of the non-coincident peak allocators used to 21

2 Coincident peak demand is the demand of each rate class at the time of the system peak demand.




allocate demand-related costs in the allocated cost of service study. As part of that rate 1

case, the PUC approved this methodology to be used to allocate forecasted transmission 2

expenses. 3

4

The coincident peak allocators are shown on Schedule ASC-11, Page 1, Line (2) and are 5

calculated on Schedule ASC-11, Page 2. Each class’s monthly coincident peak data for 6

the years 2008 and 2011 (two years with relatively normal weather) are used to develop 7

class load factors. These load factors are then multiplied by each class’s weather-8

normalized forecasted kWh for the period April 1, 2018 through March 31, 2019, 9

resulting in a coincident peak allocator that reflects more stable, weather-normalized 10

demand. Schedule ASC-11, Page 2 demonstrates the development of the coincident peak 11

allocators. 12

13

Q. Once the forecasted transmission expense has been allocated to each rate class, how 14

are the individual class charges developed? 15

A. The proposed base transmission charges are calculated on Schedule ASC-11. For rate 16

classes with demand (per kW) charges, the proposed demand charges have been designed 17

to reflect the higher of (1) the current demand charge or (2) a demand charge based upon 18

the percentage increase in 2018 transmission expense allocated to the rate class as 19

compared to that rate class’s share of 2017 expense. The amount recovered through the 20

proposed demand charges is calculated as the proposed demand charge multiplied by the 21




a forecast of billing demand. The difference between the total allocated transmission 1

expense and the transmission expenses to be recovered through the proposed demand 2

charges results in the transmission expense to be recovered through kWh charges. The 3

proposed transmission kWh charges are calculated by dividing the total transmission 4

expense to be recovered on a kWh basis by the forecasted kWh for each rate class. 5

6 Transmission Service Reconciliation 7

Q. Please explain the Company’s transmission service reconciliation for the period 8

January 1, 2017 through December 31, 2017. 9

A. The Company’s transmission service reconciliation is shown in Schedule ASC-12. The 10

reconciliation reflects actual transmission revenue for the period January 2017 through 11

December 2017, actual transmission expenses for the period January 2017 through 12

November 2017, and estimated expenses for December 2017.3 This reconciliation is 13

provided in accordance with the Company’s TSCAP, which allows for the reconciliation, 14

along with interest on any balance, and the recovery or credit of any under- or over-15

recovery, respectively. 16

17

Q. Please explain the beginning balance. 18

A. The beginning balance is the “true-up” of estimated 2016 transmission expenses 19

presented in Docket No. 4691, Schedule ASC-12, to the final expenses, for 2016. The 20

total 2016 transmission expense presented in Docket No. 4691 were $163,583,840 and 21

3 The Company has estimated transmission expense for December 2017 because this information was not available at the time of this filing.




included an estimate for December 2016. The final actual 2016 transmission expense 1

was $167,734,230, resulting in additional transmission expense to be recovered of 2

$4,150,390. This amount is reflected in the beginning balance at January 2017. In 3

addition, the beginning balance also includes an amount of $1,279,794 to be recovered 4

from customers. This amount relates to a FERC-ordered disgorgement payment received 5

by the Company. The Company provided customers the benefit in the form of a specific 6

Revenue Adjustment, reducing the estimated 2013 transmission expenses upon which 7

base transmission service rates were calculated.4 In the annual “true-up” of actual 2013 8

transmission expenses similar to that discussed above, the Company inadvertently 9

included the disgorgement credit within actual 2013 transmission expenses, reducing 10

actual 2013 transmission expenses and increasing the resulting over-recovery of 11

transmission service costs, effectively returning these funds to customers a second time. 12

13

Q. What is the balance of the transmission service reconciliation as of December 2017? 14

A. Page 1 of Schedule ASC-12 presents the reconciliation of transmission service revenue 15

and expense through December 2017. This reconciliation shows that the estimated 16

balance of the transmission reconciliation as of December 2017 is a net over-recovery of 17

approximately $3.9 million. Page 2 of Schedule ASC-12 presents the results of the 18

annual reconciliation for each rate class. 19

20

4 RIPUC Docket Number 4391, 2013 Annual Retail Rate Filing, Schedule JAL-11, page 1, Column (c).




Q. Please explain the adjustments shown on Schedule ASC-12, Page 1. 1

A. Page 1 of Schedule ASC-12 includes a $442,704 adjustment that represents the remaining 2

balance of the under-recovery of transmission expense incurred during the period January 3

2015 through December 2015, which was recovered from customers during the 12 4

months ending March 31, 2017. This amount represents the remaining balance to be 5

recovered from customers. 6

7

Q. How does the Company propose to reflect in rates the balance in the transmission 8

service reconciliation as of December 2017? 9

A. The Company proposes to implement class-specific adjustment factors to credit to or 10

recover from customers each class’ share of the net over-recovery of $3.9 million, plus 11

estimated interest during the recovery period. The calculations of the factors are shown 12

in Schedule ASC-13 and are described in more detail below. 13

14

Q. How does the Company plan to reconcile estimated expenses for December 2017 to 15

actual expenses? 16

A. Actual expenses for December 2017 will be compared to the estimated expenses included 17

in the 2017 reconciliation. The difference, actual transmission costs above or below the 18

estimate, will be reflected as the beginning balance of the transmission reconciliation for 19

the period January 2018 through December 2018, which will be filed with the PUC in 20

early 2019. 21




Q. What is the status of the balance associated with the transmission service net under 1

recovery incurred during the period January 2015 through December 2015? 2

A. Page 6 of Schedule ASC-12 presents the final balance of the net under-recovery incurred 3

during the period January 2015 through December 2015. Of the approximately $6 4

million under-recovery, the Company has under-recovered a net of $442,704. This 5

remaining balance is reflected in the current transmission service reconciliation as an 6

adjustment to the amount to be recovered by the Company, as mentioned previously. 7

8

Q. What is the status of the balance associated with the transmission service net over- 9

recovery incurred during the period January 2016 through December 2016? 10

A. Page 7 of Schedule ASC-12 presents the status of the transmission expense net over- 11

recovery incurred during the period January 2016 through December 2016. The 12

Company is currently crediting/recovering this amount during the 12 months ending 13

March 31, 2018. Page 7 of Schedule ASC-12 shows the net $6.5 million approved to be 14

credited to or recovered from customers, as appropriate, by rate class. As of January 31, 15

2018, there is a net remaining balance of approximately $1.43 million to be credited to or 16

recovered from customers. The Company will continue to recover or credit the 17

under/over-recovery, as appropriate, through March 31, 2018. The ending balance, 18

positive or negative, will be included as an adjustment to the transmission service 19

reconciliation for the period January 2018 through December 2018, which will be filed 20

with the PUC in early 2019. 21




Transmission Service Cost Adjustment Factors (TSCAF) 1

Q. What are the Company’s proposed TSCAFs? 2

A. The proposed TSCAFs for the period April 1, 2018 through March 31, 2019 are 3

presented in Schedule ASC-13. As shown on Schedule ASC-13, Page 1, Line (3), the 4

cumulative transmission service net over-recovery as of December 31, 2017, including 5

estimated interest during the credit/recovery period, is approximately $3.9 million, and 6

the proposed factors are designed on each rate class’ share of this amount. For billing 7

purposes, the TSCAFs are included with the base transmission kWh charge on 8

customers’ bills. 9

10

Q. How were the proposed factors developed? 11

A. The first step in calculating the proposed TSCAFs is to determine the over/under-12

recovery of expense for each rate class. The base transmission revenue billed to each 13

class during the period January 1, 2017 through December 31, 2017 is compared to each 14

class’s allocated share of transmission expenses for the same period. The difference is 15

the over/under-recovery of expense attributable to each class. Next, each class’s 16

over/under-recovery of expense is then divided by the forecasted kWh deliveries for 17

that class for the period April 1, 2018 through March 31, 2019 to determine the 18

individual class adjustment factors. 19

20




Transmission-Related Uncollectible Expense 1

Q. Please describe the recovery of transmission-related uncollectible expense. 2

A. Pursuant to the Company’s TSCAP, the Company is allowed to recover an allowance for 3

the Company’s uncollectible expense associated with amounts billed through 4

transmission charges at the uncollectible rate approved by the PUC. Transmission-5

related uncollectible expense is estimated for purposes of setting the Transmission 6

Service Uncollectible Factors for the upcoming year as the approved uncollectible 7

percentage applied to the sum of: (1) the forecast of base transmission expense, (2) any 8

over- or under-recovery of transmission expense during the prior year, and (3) any over- 9

or under-recovery of transmission uncollectible expense allowance during the prior year. 10

11

This amount is subject to reconciliation on an annual basis for actual transmission 12

revenue billed by the Company during the applicable period. 13

14

Q. How are the proposed transmission-related uncollectible factors calculated? 15

A. The calculation of the Transmission Uncollectible Factors is shown in Schedule ASC-14. 16

The estimated transmission uncollectible expense for 2018 is calculated by multiplying 17

the allowable uncollectible rate of 1.25% by the sum of: (1) the estimated base 18

transmission revenue for the period April 1, 2018 through March 31, 2019; (2) the 19

transmission service net over-recovery balance for 2017; and (3) the under-recovery of 20

transmission-related uncollectible expense during the period January 1, 2017 through 21




December 31, 2017. The total transmission uncollectible expense for 2018 is shown by 1

rate class on Line (6) of Schedule ASC-14. This estimate is divided by the forecasted 2

kWh deliveries for each rate class during April 1, 2018 through March 31, 2019, resulting 3

in per kWh charges for each rate class. The final Transmission Uncollectible Factors 4

include the 2017 Transmission Uncollectible Reconciliation Factors, shown on Line (9) 5

of Schedule ASC-14, that are developed in Schedule ASC-15. For billing purposes, the 6

Transmission Uncollectible and Transmission Uncollectible Reconciliation Factors are 7

included with the Transmission Service kWh charges on customers’ bills. 8

9

Q. Did the Company prepare a reconciliation of the transmission-related uncollectible 10

expense for the period ending December 31, 2017? 11

A. Yes. As explained above, on an annual basis, the Company reconciles the revenue billed 12

through the Transmission Uncollectible Factors to the Transmission Uncollectible 13

allowance based on actual Transmission Service revenue billed during the reconciliation 14

period. This reconciliation is shown in Schedule ASC-15, Page 1. The actual revenue 15

billed through the Transmission Uncollectible Factors is shown on Line (1) of Schedule 16

ASC-15, Page 1. Transmission Uncollectible Expense allowance is calculated on Lines 17

(2) through (7) as the actual Transmission Service revenue billed during the period 18

January 2017 through December 2017 multiplied by the uncollectible percentage of 19

1.25%. As indicated on Line (8), an under-recovery of $29,732 of the transmission 20

uncollectible allowance was incurred during the reconciliation period. As indicated on 21




Line (9), the net ending balance of the recovery of the prior period under-collection from 1

calendar year 2015 is $41,012, representing a net recovery due from customers. Line (8) 2

and Line (9) are then summed, resulting in a total under-recovery of $70,744, as shown 3

on Line (10). The Transmission Uncollectible Reconciliation Factors are calculated on 4

Line (17) as the transmission uncollectible over/under-recovery per rate class, including 5

interest, divided by the forecasted kWh deliveries during the period April 1, 2018 through 6

March 31, 2019. 7

8

Page 2 of Schedule ASC-15 shows the detail of the Transmission Uncollectible Factor 9

Revenue. The total revenue billed through the factors is calculated in Column (c) for 10

each rate class. The revenue associated with the recovery or refund of the prior 11

reconciliation period’s over/under-recovery, shown in Column (d), is subtracted from the 12

total revenue to determine the base revenue for the current reconciliation period. 13

14

Q. What is the status of the recovery associated with the transmission service 15

uncollectible under-recovery incurred during the period January 2015 through 16

December 2015? 17

A. Page 4 of Schedule ASC-15 presents the status of the under-recovery incurred during the 18

period January 2015 through December 2015 for each rate class. The remaining balance 19

due from customers of $41,012 has been included as adjustment to the transmission 20

21




uncollectible reconciliation for the period January 2017 through December 2017, as 1

shown on Schedule ASC-15, Page 1, Line (9). 2

3

Q. What is the status of the recovery associated with the transmission service 4

uncollectible under-recovery incurred during the period January 2016 through 5

December 2016? 6

A. Page 5 of Schedule ASC-15 presents the status of the under-recovery incurred during the 7

period January 2016 through December 2016 for each rate class. The Company will 8

continue to recover the under-recovery through March 31, 2018. The ending balance, 9

positive or negative, will be included as adjustments to the transmission uncollectible 10

reconciliation for the period January 2018 through December 2018. 11

12

VIII. Net Metering Charge and Reconciliation of Renewable Net Metering Credits and 13 Payments to Qualifying Facilities with Renewable Generation 14

Q. Please describe the costs that the Company is incurring pursuant to the Net 15

Metering Provision, RIPUC No. 2178. 16

A. Pursuant to the Company’s Net Metering Provision, RIPUC No. 2178, the Company pays 17

Renewable Net Metering Credits to an Eligible Net Metering System (Host Customer) for 18

up to one hundred percent (100%) of the Host Customer’s usage at the Eligible Net 19

Metering System site over the applicable billing period.5 The Renewable Net Metering 20

5 Additionally, municipal delivery service accounts designated by the municipality or multi-municipal collaborative are eligible for net metering within an Eligible Net Metering System site.




Credit is equal to the total kWh of electricity generated in excess of that consumed on-1

site during the billing period multiplied by the sum of the following: 2

1) SOS kWh charge for the rate class applicable to the net metering customer; 3

2) Distribution kWh charge; 4

3) Transmission kWh charge; and 5

4) Transition kWh charge. 6

7

For kWh generation between 100 percent and 125 percent of the Host Customer’s on-site 8

usage, the Company pays the SOS rate applicable to the Host Customer for all kWh 9

generated. 10

11

Q. Please describe the costs that the Company is incurring pursuant the Qualifying 12

Facility Power Purchase Rate, RIPUC No. 2098. 13

A. Pursuant to the provisions of the Qualifying Facility Power Purchase Rate, RIPUC No. 14

2098, for facilities meeting the definition of renewable energy resources, as defined in 15

R.I. Gen. Laws §39-26-5, the Company pays the SOS rate applicable to that customer for 16

each kWh generated in excess of the facility’s requirements. 17

18

Q. Does the Company receive payments from ISO-NE for energy generated by net 19

metered customers and renewable Qualifying Facilities? 20

A. Yes. For kWh generated and exported onto the distribution system by both eligible 21




renewable net metering customers and renewable Qualifying Facilities that are registered 1

with ISO-NE as generating assets, the Company receives payments from ISO-NE for the 2

sale of this energy in the market, as well as capacity payments, if any. These payments 3

are used to offset the Renewable Net Metering Credits paid to Host Customers and 4

payments to renewable Qualifying Facilities. 5

6

Q. How does the Company recover the cost of the Renewable Net Metering Credits 7

paid to Host Customers and the payments to renewable Qualifying Facilities? 8

A. Pursuant to the Company’s tariffs, the Company recovers through a Net Metering Charge 9

the sum of the following: (1) all Renewable Net Metering Credits paid to eligible net 10

metering customers, less any payments from ISO-NE for the sale of excess generation; 11

and (2) the difference between the payments made to Qualifying Facilities with 12

renewable generation at the SOS rate and the net proceeds received from ISO-NE for 13

market energy sold and any capacity payments. The Net Metering Charge is a uniform 14

per-kWh charge applicable to all customers and is included with the LTC Recovery 15

Factor on customer bills, labeled as the Renewable Energy Distribution charge. 16

17

Q. What is the total cost that the Company is proposing to recover through the Net 18

Metering Charge? 19

A. The Net Metering reconciliation is shown in Schedule ASC-16. The total amount of 20

Renewable Net Metering Credits paid during 2017 totaled $3,933,952, as shown in 21




Column (a) of Page 1. The net proceeds received during 2017 from ISO-NE for exported 1

generation totaled $1,142,180, as shown in Column (b). The difference between the 2

payments made to Qualifying Facilities with renewable generation at the SOS rate and 3

the net proceeds received from ISO-NE for market energy sold and capacity payments 4

totaled $425,790 as shown in Column (c). The total costs incurred during the period 5

January 1, 2017 through December 31, 2017 is $3,149,512, as shown in Column (e). 6

7

Q. Please describe the adjustments shown in the Net Metering reconciliation, Schedule 8

ASC-16, Column (d). 9

A. The adjustment of $97,614 shown in January 2017 reflects additional Net Metering and 10

Qualifying Facility energy sales resettled through the ISO-New England prior to January 11

2017 that had previously not been reflected in the Company’s annual retail rate filings. 12

The Company had reflected these energy sales as either energy sales for Long Term 13

Contract (LTC) facilities or as offsetting credits to SOS Spot Market energy purchases. 14

As a result, the Company understated the total Energy Sales to ISO-NE for Net-Metered 15

Customers or overstated the Qualifying Facilities Power Purchase Recoverable Costs in 16

prior years’ reconciliations. The purpose of the adjustment is to reflect the correct 17

amount of costs and proceeds to all customers that are billed the Net Metering Charge. 18

Column (d) also includes an April 2017 adjustment of $29,564, which is the remaining 19

unrecovered balance of the costs incurred during 2015 and recovered from customers 20

during the period ending March 31, 2017, as shown on Page 3. 21




Q. Is the Company proposing a Net Metering Charge for April 1, 2018? 1

A. Yes. As shown on Schedule ASC-16, Page 1, item (2), the Company is proposing a Net 2

Metering Charge of 0.043¢ per kWh. 3

4

Q. Please describe Schedule ASC-17. 5

A. Schedule ASC-17 is the Company’s Net Metering report. This schedule includes a listing 6

of all eligible net metering facilities in the Company’s service territory, along with a 7

description of each unit, including fuel type, capacity, and interconnection date. An 8

estimate of each unit’s annual kWh production is also included in the report. 9

10

IX. LTC Recovery Factor and Reconciliation 11

Q. Please describe the LTC Recovery Provision. 12

A. Pursuant to LTC Recovery Provision, RIPUC No. 2174, the Company is allowed to 13

recover the costs incurred in accordance with the provisions of R.I. Gen. Laws § 39-26.1, 14

Long-Term Contracting Standard for Renewable Energy, and R.I. Gen. Laws § 39-26.2, 15

Distributed Generation Standard Contracts. Pursuant to Rhode Island law, the Company 16

is required to enter into contracts with eligible renewable energy resources at fixed prices 17

for the purchase of energy, capacity, and Renewable Energy Certificates (RECs) 18

(collectively, the Contract Products). The Company will sell the energy purchased 19

through the contracts into the ISO-NE energy market and will use the RECs to satisfy the 20

Company’s REC obligation associated with SOS. The difference between the cost 21




incurred under each contract, equal to the fixed contract price multiplied by the 1

generation of the facility, and the net proceeds that the Company receives for the sale of 2

the Contract Products, is referred to as the above market contract cost. Pursuant to R.I. 3

Gen. Laws § 39-26.1-5(f), the above market contract costs must be recovered from all 4

retail delivery service customers through a uniform per-kWh factor. In addition, R.I. 5

Gen. Laws § 39-26.1-4 authorizes the Company to recover 2.75 percent of the total 6

payments made under each contract as remuneration. Finally, certain administrative and 7

other costs authorized through various sections of the statutes will be tracked and 8

recovered annually. 9

10

On an annual basis, the Company is required to reconcile the revenue billed through the 11

LTC Recovery Factor and the expenses incurred pursuant to the LTCRER Reconciliation 12

Provision, R.I.P.U.C. No. 2175. 13

14

Q. Has the Company prepared a reconciliation of the LTC Recovery Factor? 15

A. Yes. The reconciliation of the LTC Recovery Factor is included in Schedule ASC-18. 16

Page 1 contains a summary of revenue and expenses while pages 3 and 4 contain detailed 17

revenue and expense information, respectively. Page 5 contains the status of the under-18

recovered balance incurred through December 2016 that is being recovered from 19

customers during the period April 1, 2017 through March 31, 2018. Page 6 contains the 20

21




status of the under-recovered balance incurred in from January 2015 to December 2015. 1

The ending balance is included as an adjustment on Page 1, Column (d). 2

3

Q. Please summarize the results of the Company’s LTC Recovery Factor reconciliation 4

for the period January 1, 2017 through December 31, 2017. 5

A. Page 1, Column (b) shows the revenue billed each month through the LTC Recovery 6

Factor during 2017 totaling approximately $40 million. Column (c) shows the monthly 7

expense totaling approximately $43.5 million for the 12 months ending December 31, 8

2017. Column (d) includes two adjustments: an adjustment in January 2017 of $510,905 9

which is a cumulative correction, including interest, of incorrectly presenting energy 10

sales resettlement amounts related to Long Term Contracting (LTC) facilities and which 11

will be discussed below, and an adjustment of $969,272, which is the remaining 12

unrecovered balance of the under-recovery incurred during 2015 and recovered from 13

customers during the period ending March 31, 2017. Column (e) shows the over- or 14

under-recovery of expense for each month. Column (f) shows the cumulative over- or 15

under-recovery. Column (f) shows an ending under-recovery balance (before interest) of 16

approximately $4.9 million. 17

18




Q. Please describe the adjustments shown in the LTC reconciliation, Schedule ASC-18, 1

Column (d). 2

A. The adjustment of $510,905 shown in January 2017 reflects additional energy sales 3

associated with LTC facilities that were resettled through the ISO-NE prior to January 4

2017 that had previously not been reflected in the Company’s annual retail rate filings. 5

The Company had incorrectly allocated these energy sales as offsetting credits to SOS 6

Spot Market energy purchases. As a result, the Company overstated the total Energy 7

Sales credit through ISO-NE for LTC facilities in prior years’ reconciliations. The 8

purpose of the adjustment is to reflect the correct amount of net proceeds to all customers 9

that are billed the LTC Recovery Factor. Column (d) also includes an April 2017 10

adjustment of $969,272, which is the remaining unrecovered balance of the under-11

recovery incurred during 2015 and recovered from customers during the period ending 12

March 31, 2017, as shown on Page 6. 13

14

Q. What is the LTC Recovery Factor proposed to be effective April 1, 2018? 15

A. The proposed LTC Recovery Reconciliation Factor effective April 1, 2018 is 0.068¢ per 16

kWh. The calculation of the factor is shown on Schedule ASC-18, Page 1, Lines (4) 17

through (8). The under-recovery of $5 million, including interest, is divided by the 18

forecasted kWh delivery during the recovery period, resulting in a charge of 0.068¢ per 19

kWh. Line (7) provides for an adjustment to the LTC Recovery Factor for uncollectible 20

revenue, which does not result in an incremental factor. Line (9) shows the currently 21




effective base LTC Recovery Factor charge of 0.519¢ per kWh, effective January 1, 1

2018, that was designed to recover the estimated above-market costs that Company 2

expected to incur during the period January 1, 2018 through June 30, 2018 associated 3

with long-term contracts. This factor will terminate on June 30, 2018 at which time a 4

new charge or credit factor will become effective to either recover or credit the estimated 5

above or below market value of Contract Products during the period July 1, 2018 through 6

December 31, 2018. Line (10) shows the net LTC Recovery Factor of 0.587¢ per kWh to 7

be effective April 1, 2018 through June 30, 2018. 8

9

Q. Please describe the revenue billed through the LTC Recovery Factor and reflected 10

in Column (b) of the LTC reconciliation shown on Schedule ASC-18, Page 1. 11

A. Page 3 contains the derivation of the LTC Recovery Factor revenue billed during the 12

reconciliation period. For billing purposes, the LTC Recovery Factor and the Net 13

Metering Charge are combined and shown on customers’ bills as the Renewable Energy 14

Distribution Charge. Column (a) on Page 3 shows the monthly Renewable Energy 15

Distribution Charge. The LTC Recovery Factor revenue reflected in the LTC 16

reconciliation is the result of disaggregating the revenue billed through the Renewable 17

Energy Distribution Charge. The first step is to remove the revenue related to the Net 18

Metering Charge portion of the Renewable Energy Distribution Charge revenue, which is 19

shown in Column (b). The LTC Recovery Factor revenue is shown in Column (c) and is 20

the difference between the Renewable Energy Distribution Charge revenue shown in 21




Column (a) and the Net Metering Charge revenue shown in Column (b). Column (d) 1

represents the revenue associated with the prior year’s under-recovery. The revenue 2

supporting the uncollectible expense allowance is shown in Column (f). The remaining 3

LTC Recovery Factor revenue shown in Column (g) represents the base revenue 4

available to offset LTC expenses incurred during the reconciliation period. 5

6

Q. Please describe the expenses included in the LTC Recovery Factor reconciliation 7

and shown in Column (c) of Schedule ASC-18, Page 1. 8

A. Page 4 shows a summary of monthly expenses associated with the Company’s long term 9

and distributed generation standard contracts. The total contract cost shown in Column 10

(a) less capacity revenue in Column (b) results in net contract payments shown in 11

Column (c) for the 12-month period. The Contract Products, consisting of the energy 12

market proceeds resulting from the sale of the purchased energy into the ISO-NE energy 13

market and the value of the RECs, are shown in Columns (d) and (e), respectively. The 14

above market cost in Column (f) is the net contract cost less the value received for the 15

Contract Products. Column (g) shows Other Charges and Credits, representing forfeited 16

performance guarantee deposits retained from resources that did not complete required 17

contract milestones. Column (h) shows the contract remuneration. Column (i) shows the 18

administrative costs incurred in relation to bidding capacity on behalf of qualified DG 19

projects into the ISO New England Forward Capacity Market (FCM), as was approved in 20

RIPUC Docket No. 4676, Proposal to Bid Capacity of Customer-Owned DG Facilities 21




into the Forward Capacity Market. Capacity Supply Obligation Payments, and associated 1

costs and penalties are anticipated to begin in June 2018, and the resulting Customer 2

Share of Net Market Proceeds will be reflected in the Calendar Year 2018 LTCRER 3

reconciliation filing, to be filed in February 2019. Column (i) shows the total costs to be 4

recovered for the year. 5

6

Q. Please describe the contract costs in more detail. 7

A. As described above, the Company executes contracts with eligible renewable resources to 8

purchase energy, capacity, and RECs at a bundled price. Twenty-nine resources that 9

have executed contracts under either the long-term contracting or distributed generation 10

standard contract statutes were commercially operational for at least one or more months 11

during the reconciliation period. The amount paid each month under the individual 12

contracts is equal to the MWh generated by the renewable resource multiplied by each 13

contract’s bundled price. If the resource has bid capacity into the ISO-NE Forward 14

Capacity Market and is receiving direct capacity payments from ISO-NE, these payments 15

are reflected on the monthly contract invoice as a reduction to the total payment owed to 16

the resource. 17

18

Q. How are the energy market proceeds determined? 19

A. The Company sells the energy generated by each renewable resource into the ISO-NE 20

21




energy market and receives a payment from ISO-NE equal to the hourly generation of 1

each resource multiplied by the hourly locational marginal price. 2

3

Q. Please describe the treatment of RECs in the LTCRER reconciliation. 4

A. As first approved in the Company’s 2013 Renewable Energy Standard Plan in Docket 5

No. 4315, the Company utilizes the RECs produced by each resource to satisfy its RES 6

obligation for SOS. The Company determines the market value of the RECs on a 7

quarterly basis as they are delivered. RECs are delivered to the Company through the 8

GIS on a quarterly basis, and the Company assesses their value at delivery every three 9

months by calculating the average of the available market prices two weeks before and 10

after the delivery. Market price information includes recent REC solicitation results, 11

broker information, and published indices in accordance with the methodology approved 12

in the RES Plan. 13

14

To illustrate the valuation methodology, after the first quarter of generation is completed, 15

the RECs are “minted” or created within the GIS and then delivered to the Company. At 16

this point, the Company averages the available market price points for the period two 17

weeks prior to and after the delivery date. This calculation produces the current market 18

value, which is then applied to the quantity of RECs delivered for that quarterly period. 19

On an annual basis, there are four REC deliveries through the GIS, and those quarterly 20

21




deliveries are valued using this methodology. Thus the value of the each delivery of 1

RECs reflects the market price at the time they were delivered. 2

3

The value of the generated RECs is recorded in the LTC Recovery Factor reconciliation 4

as a credit, or an offset to total cost, and is simultaneously recorded in the RES 5

reconciliation6 as an expense. 6

7

Q. Please describe the calculation of the contract remuneration. 8

A. The contract remuneration is shown in Schedule ASC-18, Page 4, Column (h) and is 9

calculated as 2.75% of the actual net contract payments shown in Column (c). 10

11

Q. What is the status of the under-recovery of costs incurred as of December 2016? 12

A. Schedule ASC-18, Page 5, contains the status of the under-recovery incurred during the 13

period January 2016 through December 2016. This balance is currently being recovered 14

from customers during the period April 1, 2017 through March 31, 2018. The Company 15

will continue to recover the under-recovery through March 31, 2018. The ending 16

balances, positive or negative, will be included as an adjustment to the LTC Recovery 17

reconciliation for the period January 2018 through December 2018, which will be filed 18

with the PUC in early 2019. 19

20

6 Pursuant to R.I. Gen. Laws § 39-26-1.




Q. What is the status of the under-recovery of costs incurred as of December 2015? 1

A. Schedule ASC-18, Page 6, presents the final balance of the under-recovery incurred 2

during the period January 2015 through December 2015. Of the approximately $9.4 3

million under-recovery, the Company under-recovered a net of $969,272. This remaining 4

balance is reflected in the current reconciliation as an adjustment to the amount to be 5

recovered by the Company. 6

7

Q. Has the Company made any other adjustments in this filing? 8

A. Yes. The Company has made an adjustment to revenue in each of the following 9

reconciliations in January 2017: transmission, Standard Offer Service, transition, and 10

LTC, to reflect additional revenue that was inadvertently not billed to a single large 11

customer due to an incorrectly programmed meter at the customer’s service location. The 12

meter was correctly reprogrammed in September 2016. The improperly-programmed 13

meter reported under-stated usage and, consequently, under-billed the customer. The 14

Company elected to not rebill the customer because the under-reported usage was not the 15

result of a customer action, and the customer was not aware of the under-reported usage. 16

In order to ensure that all customers are not impacted by having less revenue in these 17

reconciliations, the Company is reflecting through these adjustments additional revenue 18

and interest, where applicable, in these reconciliations. The Company will include 19

similar adjustments in upcoming reconciliation filings. 20

21




X. Typical Bills 1

Q. Has the Company provided a typical bill analysis to illustrate the impact of the 2

proposed rate changes? 3

A. Yes. The typical bill analysis is included in Schedule ASC-19. The impact of all rate 4

changes proposed in this filing on a typical residential SOS customer using 500 kWh per 5

month is an increase of $3.07, from $104.26 to $107.33 or approximately 2.9% percent. 6

7

XI. Summary of Retail Delivery Rates 8

Q. Is the Company including a revised Summary of Retail Delivery Rates tariff, 9

RIPUC No. 2095, or Summary of Rates – Standard Offer, RIPUC 2096, in this 10

filing? 11

A. No, the Company is not revising these tariffs at this time. The Company currently has 12

rate changes for April 1, 2018 pending approval by the PUC in Docket No. 4783, the 13

Fiscal Year 2019 Electric Infrastructure, Safety, and Reliability Plan. In addition, the 14

Company will submit its RES filing before March 1, 2018 and will propose its RES 15

charge effective April 1, 2018. Finally, the Company has also proposed base Standard 16

Offer Service rates for effect, April 1, 2018, pending approval, in RIPUC No. 4692. 17

Therefore, the Company will submit its revised Summary of Rates Tariffs as compliance 18

filing once the PUC has issued its decision in all dockets related to rate changes proposed 19

for April 1, 2018. 20

21




XII. Conclusion 1

Q. Does this conclude your testimony? 2

A. Yes, it does.3

Schedules of

A

dam S. C

rary



WITNESS: ADAM S. CRARY SCHEDULES

Schedules of Adam S. Crary

Schedule ASC-1 Summary of Proposed Rate Changes Effective April 1, 2018 through March 31, 2019

Schedule ASC-2 Standard Offer Service Reconciliation for the period January 2017 through December

2017

Schedule ASC-3 Calculation of Standard Offer Adjustment Factors

Schedule ASC-4 Calculation of Standard Offer Service Administrative Cost Factors

Schedule ASC-5 Standard Offer Service Administrative Cost Adjustment Reconciliation for the period

January 2017 through December 2017

Schedule ASC-6 Cash Working Capital Analysis

Schedule ASC-7 Calculation of SOS Administrative Cost Reconciliation Adjustment Factors

Schedule ASC-8 Unbilled SOS Billing Adjustment

Schedule ASC-9 Calculation of Proposed Non-Bypassable Transition Charge

Schedule ASC-10 Non-Bypassable Transition Charge Reconciliation and Non-Bypassable Transition

Adjustment Charge Reconciliation for the period January 2017 through December

2017

Schedule ASC-11 Calculation of Proposed Base Transmission Charges

Schedule ASC-12 Transmission Service Reconciliation for the period January 2017 through December

2017

Schedule ASC-13 Calculation of Proposed Transmission Adjustment Factors

Schedule ASC-14 Calculation of Proposed Transmission Uncollectible Factors

Schedule ASC-15 Transmission Uncollectible Factor Reconciliation for the period January 2017

through December 2017

Schedule ASC-16 Calculation of Net Metering Charge

Schedule ASC-17 Net Metering Report for 2017

Schedule ASC-18 LTCRER Reconciliation and Calculation of Proposed LTC Factor

Schedule ASC-19 Typical Bill Analysis

Schedule A

SC-1




Schedule ASC-1

Summary of Proposed Rate Changes Effective April 1, 2018 through March 31, 2019

Standard Standard

Offer Offer Service Transition Net

Rate Adjustment Administrative Transition Adjustment Transition

Class Factor (1) Cost Factor (1) Charge Charge Charge

(a) (b) (d) (e) (f)

Schedule ASC-3 Schedule ASC-4 Schedule ASC-9 Schedule ASC-10 (d) + (e)

(1) A-16 $0.00183 $0.00159 ($0.00083) ($0.00004) ($0.00087)

(2) A-60 $0.00183 $0.00159 ($0.00083) ($0.00004) ($0.00087)

(3) C-06 $0.00125 $0.00159 ($0.00083) ($0.00004) ($0.00087)

(4) G-02 per kWh $0.00125 $0.00159 ($0.00083) ($0.00004) ($0.00087)

(5) G-32/B-32 per kWh ($0.00751) $0.00162 ($0.00083) ($0.00004) ($0.00087)

(6) G-62/B-62 per kWh ($0.00751) $0.00162 ($0.00083) ($0.00004) ($0.00087)

(7) Streetlights $0.00125 $0.00159 ($0.00083) ($0.00004) ($0.00087)

(8) X-01 per kWh ($0.00751) $0.00162 ($0.00083) ($0.00004) ($0.00087)

Base Transmission Transmission Net Net

Rate Transmission Adjustment Factor Uncollectible Transmission Metering LTCRER

Class Charge Charge(Credit) Factor Charge Surcharge Charge

(g) (h) (i) (j) (k) (l)

Schedule ASC-11 Schedule ASC-13 Schedule ASC-14 (g) + (h) + (i) Schedule ASC-16 Schedule ASC-18

(9) A-16 $0.03154 $0.00076 $0.00041 $0.03271 $0.00043 $0.00587

(10) A-60 $0.03154 $0.00076 $0.00041 $0.03271 $0.00043 $0.00587

(11) C-06 $0.03167 ($0.00474) $0.00033 $0.02726 $0.00043 $0.00587

(12) G-02 per kWh $0.01231 ($0.00236) $0.00033 $0.01028 $0.00043 $0.00587

(13) G-02 per kW $4.37 $4.37

(14) G-32/B-32 per kWh $0.01159 ($0.00100) $0.00029 $0.01088 $0.00043 $0.00587

(15) G-32/B-32 per kW $4.69 $4.69

(16) G-62/B-62 per kWh $0.01489 $0.00242 $0.00032 $0.01763 $0.00043 $0.00587

(17) G-62/B-62 per kW $3.40 $3.40

(18) Streetlights $0.01440 $0.01297 $0.00035 $0.02772 $0.00043 $0.00587

(19) X-01 per kWh $0.01489 $0.00242 $0.00032 $0.01763 $0.00043 $0.00587

(20) X-01 per kW $3.40 $3.40

(1) To be included with Standard Offer Service rate for billing purposes

The Narragansett Electric Company

Summary of Proposed Rate Changes for April 1, 2018

The Narragansett Electric Company d//b/a National Grid RIPUC Docket No. 4805 2018 Electric Retail Rate Filing Schedule ASC-1 Page 1 of 1

Schedule ASC

-2




Schedule ASC-2

Standard Offer Service Reconciliation For the period January 2017 through December 2017

Over/(Under) Over/(Under)

Beginning SOS SOS Monthly Ending

Month Balance Revenue Expense Over/(Under) Balance

(a) (b) (c) (d) (e)

(1) Jan-17 $0 $12,932,837 $30,318,979 ($17,386,142) ($17,386,142)

Feb-17 ($17,386,142) $25,911,447 $25,732,357 $179,091 ($17,207,052)

Mar-17 ($17,207,052) $23,872,820 $22,271,795 $1,601,025 ($15,606,027)

Apr-17 ($15,606,027) $21,091,474 $14,320,001 $6,771,473 ($8,834,554)

May-17 ($8,834,554) $15,947,303 $14,209,579 $1,737,724 ($7,096,829)

Jun-17 ($7,096,829) $18,259,693 $23,665,469 ($5,405,776) ($12,502,605)

Jul-17 ($12,502,605) $24,991,349 $28,258,865 ($3,267,516) ($15,770,121)

Aug-17 ($15,770,121) $25,649,795 $25,678,708 ($28,913) ($15,799,034)

Sep-17 ($15,799,034) $22,445,877 $22,139,612 $306,265 ($15,492,768)

Oct-17 ($15,492,768) $21,906,874 $20,845,461 $1,061,413 ($14,431,356)

Nov-17 ($14,431,356) $26,353,273 $23,082,951 $3,270,322 ($11,161,034)

Dec-17 ($11,161,034) $28,163,037 $39,389,079 ($11,226,043) ($22,387,076)

(2) Jan-18 ($22,387,076) $16,921,581 $16,921,581 ($5,465,496)

Subtotal $0 $284,447,360 $289,912,855 ($5,465,496) ($5,465,496)

Adjustments

(3) Remaining Balance from Over(Under) Recovery incurred during 2015 $1,175,565

(4) Cumulative Spot Market Purchase Corrections through December 2016 Incl. Interest $411,791

(5) Total Net Unbilled SOS Billing Adjustments ($137,654)

(6) Total Adjustments $1,449,702

(7) Ending Balance Prior to Application of Interest ($4,015,793)

(8) Interest ($37,949)

(9) Ending Balance Including Interest ($4,053,743)

(1) Reflects revenues based on kWhs consumed after January 1

(2) Reflects revenues based on kWhs consumed prior to January 1

(3) Sum of Pages 2, 3, and 4, Line (3)

(4) Sum of Page 2, Line (4) and Page 3, Line (4)

(5) Schedule ASC-8, Page 1, Column (c) Total

(6) Line (3) + Line (4) + Line (5)

(7) Column (e) Total + Line (6)

(8) [(Beginning balance + Ending balance) ÷ 2] x [(2.14% x 2/12)+(1.84% x 10/12)]

(9) Line (7) + Line (8)

Column (a) Column (e) from previous row

Column (b) Pages 2, 3 and 4, Column (b)

Column (c) Pages 2, 3 and 4, Column (c)

Column (d) Column (b) - Column (c)

Column (e) Column (a) + Column (d)

STANDARD OFFER SERVICE RECONCILIATIONFor the Period January 1, 2017 through December 31, 2017

BASE RECONCILIATION - ALL CLASSES



Beginning Monthly Ending


(a) (b) (c) (d) (e)

(1) Jan-17 $0 $7,821,932 $20,773,107 ($12,951,175) ($12,951,175)

Feb-17 ($12,951,175) $17,394,360 $17,245,315 $149,045 ($12,802,130)

Mar-17 ($12,802,130) $16,197,089 $15,118,771 $1,078,318 ($11,723,812)

Apr-17 ($11,723,812) $14,805,995 $9,894,366 $4,911,629 ($6,812,183)

May-17 ($6,812,183) $11,185,656 $9,413,058 $1,772,597 ($5,039,586)

Jun-17 ($5,039,586) $12,767,043 $16,682,960 ($3,915,917) ($8,955,503)

Jul-17 ($8,955,503) $17,550,737 $20,176,316 ($2,625,579) ($11,581,081)

Aug-17 ($11,581,081) $17,954,678 $17,621,892 $332,787 ($11,248,295)

Sep-17 ($11,248,295) $15,319,540 $15,295,302 $24,238 ($11,224,057)

Oct-17 ($11,224,057) $14,943,231 $14,506,003 $437,228 ($10,786,829)

Nov-17 ($10,786,829) $18,917,418 $16,101,836 $2,815,582 ($7,971,247)

Dec-17 ($7,971,247) $20,207,841 $29,436,224 ($9,228,383) ($17,199,630)

(2) Jan-18 ($17,199,630) $12,143,367 $12,143,367 ($5,056,263)

Adjustments

(3) Remaining Balance from Over(Under) Recovery incurred during 2015 $195,522

(4) $304,707

(5) Total Net Unbilled SOS Billing Adjustments - Residential ($116,429)

(6) Total Adjustments $383,801


(8) Interest ($44,155)




(3) Final values on Page 7, Section 1, column (g)

(4) Cumulative Spot Market Purchase Resettlement Corrections, incl. interest. - Residential Allocation

(5) Schedule ASC-8, page 1, Column (a) Total

(6) Line (3) + Line (4) + Line (5)



(9) Line (7) + Line (8)

(a) Column (e) from previous row

(b) Page 5, Column (a) - Residential

(c) Page 6, Column (d) - Residential

(d) Column (b) - Column (c)

(e) Column (a) + Column (d)

Residential


Base Reconciliation - By Customer Group

Cumulative Residential Spot Market Purchase Corrections through December 2016 Incl. Interest





(a) (b) (c) (d) (e)

(1) Jan-17 $0 $2,974,455 $7,880,792 ($4,906,337) ($4,906,337)

Feb-17 ($4,906,337) $7,013,096 $6,944,046 $69,050 ($4,837,287)

Mar-17 ($4,837,287) $6,372,766 $5,991,897 $380,869 ($4,456,418)

Apr-17 ($4,456,418) $5,208,079 $3,600,585 $1,607,494 ($2,848,924)

May-17 ($2,848,924) $3,904,078 $3,604,367 $299,711 ($2,549,213)

Jun-17 ($2,549,213) $4,535,980 $5,930,798 ($1,394,818) ($3,944,032)

Jul-17 ($3,944,032) $6,087,589 $6,713,683 ($626,094) ($4,570,125)

Aug-17 ($4,570,125) $6,206,605 $6,643,777 ($437,172) ($5,007,297)

Sep-17 ($5,007,297) $5,824,614 $5,498,754 $325,860 ($4,681,438)

Oct-17 ($4,681,438) $5,564,846 $5,370,220 $194,626 ($4,486,812)

Nov-17 ($4,486,812) $6,320,374 $5,836,096 $484,278 ($4,002,534)

Dec-17 ($4,002,534) $6,686,752 $7,846,454 ($1,159,702) ($5,162,235)

(2) Jan-18 ($5,162,235) $3,946,550 $3,946,550 ($1,215,685)

Adjustments

(3) Remaining Balance from Over(Under) Recovery incurred during 2015 ($42,760)

(4) $107,084

(5) Total Net Unbilled SOS Billing Adjustments - Commercial ($21,225)

(6) Total Adjustments $43,098


(8) Interest ($11,081)





(4) Cumulative Spot Market Purchase Resettlement Corrections, incl. interest. - Commercial Allocation

(5) Schedule ASC-8, page 1, Column (b) Total

(6) Line (3) + Line (4) + Line (5)



(9) Line (7) + Line (8)


(b) Page 5, Column (c) - Commercial

(c) Page 6, Column (d) - Commercial



Commercial



Cumulative Commercial Spot Market Purchase Corrections through December 2016 Incl. Interest





(a) (b) (c) (d) (e)

(1) Jan-17 $0 $2,136,450 $1,665,080 $471,370 $471,370

Feb-17 $471,370 $1,503,991 $1,542,996 ($39,005) $432,365

Mar-17 $432,365 $1,302,965 $1,161,127 $141,838 $574,203

Apr-17 $574,203 $1,077,401 $825,050 $252,350 $826,554

May-17 $826,554 $857,569 $1,192,153 ($334,584) $491,970

Jun-17 $491,970 $956,670 $1,051,710 ($95,041) $396,929

Jul-17 $396,929 $1,353,023 $1,368,866 ($15,843) $381,086

Aug-17 $381,086 $1,488,512 $1,413,039 $75,473 $456,558

Sep-17 $456,558 $1,301,724 $1,345,556 ($43,832) $412,727

Oct-17 $412,727 $1,398,797 $969,239 $429,559 $842,285

Nov-17 $842,285 $1,115,481 $1,145,019 ($29,538) $812,747

Dec-17 $812,747 $1,268,443 $2,106,401 ($837,958) ($25,211)

(2) Jan-18 ($25,211) $831,664 $831,664 $806,453

Adjustments

(3) Remaining Balance from Over(Under) Recovery incurred during 2015 $1,022,803

(4) Ending Balance Prior to Application of Interest $1,829,256

(5) Interest $17,286

(6) Ending Balance Including Interest $1,846,542






(6) Line (5) + Line (6)


(b) Page 5, Column (c) - Industrial

(c) Page 6, Column (c) - Industrial



Industrial




Res

iden

tial

Gra

nd

Tot

al B

ase

Bas

eH

VM

Tot

al B

ase

Bas

eH

VM

Tot

al B

ase

Tot

al B

ase

Rev

enue

sR

even

ues

Dis

coun

tR

even

ues

Rev

enue

sD

isco

unt

Rev

enue

sR

even

ue

(a)

(a)

(b)

(c)

(a)

(b)

(c)

(d)

(1)

Jan-

17$7

,821

,932

$2,9

74,8

57($

402)

$2,9

74,4

55$2

,138

,489

($2,

039)

$2,1

36,4

50$1

2,93

2,83

7

Feb-

17$1

7,39

4,36

0$7

,013

,806

($71

0)$7

,013

,096

$1,5

07,8

33($

3,84

2)$1

,503

,991

$25,

911,

447

Mar

-17

$16,

197,

089

$6,3

73,4

82($

717)

$6,3

72,7

66$1

,305

,634

($2,

670)

$1,3

02,9

65$2

3,87

2,82

0

Apr

-17

$14,

805,

995

$5,2

08,4

71($

392)

$5,2

08,0

79$1

,079

,913

($2,

512)

$1,0

77,4

01$2

1,09

1,47

4

May

-17

$11,

185,

656

$3,9

04,3

35($

257)

$3,9

04,0

78$8

59,6

55($

2,08

5)$8

57,5

69$1

5,94

7,30

3

Jun-

17$1

2,76

7,04

3$4

,536

,506

($52

6)$4

,535

,980

$959

,592

($2,

922)

$956

,670

$18,

259,

693

Jul-

17$1

7,55

0,73

7$6

,088

,097

($50

8)$6

,087

,589

$1,3

57,1

62($

4,13

9)$1

,353

,023

$24,

991,

349

Aug

-17

$17,

954,

678

$6,2

07,1

62($

557)

$6,2

06,6

05$1

,492

,400

($3,

888)

$1,4

88,5

12$2

5,64

9,79

5

Sep-

17$1

5,31

9,54

0$5

,825

,475

($86

1)$5

,824

,614

$1,3

05,0

57($

3,33

3)$1

,301

,724

$22,

445,

877

Oct

-17

$14,

943,

231

$5,5

65,4

48($

603)

$5,5

64,8

46$1

,403

,282

($4,

484)

$1,3

98,7

97$2

1,90

6,87

4

Nov

-17

$18,

917,

418

$6,3

20,9

80($

606)

$6,3

20,3

74$1

,118

,954

($3,

473)

$1,1

15,4

81$2

6,35

3,27

3

Dec

-17

$20,

207,

841

$6,6

87,3

81($

629)

$6,6

86,7

52$1

,272

,526

($4,

083)

$1,2

68,4

43$2

8,16

3,03

7

(2)

Jan-

18$1

2,14

3,36

7$3

,946

,820

($27

0)$3

,946

,550

$833

,493

($1,

829)

$831

,664

$16,

921,

581

Tot

als

$197

,208

,886

$70,

652,

820

($7,

036)

$70,

645,

784

$16,

633,

988

($41

,298

)$1

6,59

2,69

0$2

84,4

47,3

60

(1)R

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Jan

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1

(a)

Mon

thly

rev

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rep

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(b)

Mon

thly

rev

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rep

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(c)

Col

umn

(a)

+ C

olum

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)

(d)

Res

iden

tial

Col

umn

(a)

+ C

omm

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olum

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) +

Ind

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n (c

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STA

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CIL

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Rev

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For

the

Peri

od J

anua

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, 201

7 th

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31, 2

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Com

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stri

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Mon

thB

ase

Sta

ndar

d O

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Exp

ense

Sup

plie

r R

eall

ocat

ions

&

Oth

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Spo

t Mar

ket

Pur

chas

es

Tot

alB

ase

Sta

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d O

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Exp

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Sup

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&

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Pur

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Sup

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Tot

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Exp

ense

(a)

(b)

(c)

(d)

(a)

(b)

(c)

(d)

(a)

(b)

(c)

(e)

Jan-

17$1

9,49

2,09

3$2

07,5

25$1

,073

,488

$20,

773,

107

$7,4

89,6

45$2

1,61

3$3

69,5

34$7

,880

,792

$1

,723

,855

($58

,775

)$1

,665

,080

$3

0,31

8,97

9

Feb

-17

$16,

511,

574

($15

6,67

7)$8

90,4

18$1

7,24

5,31

5 $6

,565

,087

$50,

570

$328

,389

$6,9

44,0

46

$1,5

93,8

69($

50,8

74)

$1,5

42,9

96

$25,

732,

357

Mar

-17

$13,

622,

644

$277

,747

$1,2

18,3

81$1

5,11

8,77

1 $5

,488

,073

$28,

538

$475

,286

$5,9

91,8

97

$1,2

40,6

76($

79,5

49)

$1,1

61,1

27

$22,

271,

795

Apr

-17

$8,8

48,6

23$4

75,3

61$5

70,3

82$9

,894

,366

$3

,339

,969

$29,

416

$231

,199

$3,6

00,5

85

$871

,120

($46

,070

)$8

25,0

50

$14,

320,

001

May

-17

$8,2

63,7

69$3

93,4

13$7

55,8

76$9

,413

,058

$3

,158

,152

$105

,040

$341

,175

$3,6

04,3

67

$906

,350

$285

,803

$1,1

92,1

53

$14,

209,

579

Jun-

17$1

4,33

1,97

6$6

43,3

18$1

,707

,666

$16,

682,

960

$5,2

39,7

39$1

6,10

1$6

74,9

58$5

,930

,798

$1

,211

,612

($15

9,90

2)$1

,051

,710

$2

3,66

5,46

9

Jul-

17$1

7,28

0,56

0$6

78,4

54$2

,217

,301

$20,

176,

316

$6,0

94,0

82($

117,

566)

$737

,166

$6,7

13,6

83

$1,4

78,8

63($

109,

996)

$1,3

68,8

66

$28,

258,

865

Aug

-17

$16,

010,

327

$130

,507

$1,4

81,0

58$1

7,62

1,89

2 $6

,141

,958

$32,

350

$469

,468

$6,6

43,7

77

$1,4

35,9

15($

22,8

76)

$1,4

13,0

39

$25,

678,

708

Sep

-17

$13,

614,

568

$58,

021

$1,6

22,7

12$1

5,29

5,30

2 $4

,942

,958

($53

,624

)$6

09,4

20$5

,498

,754

$1

,421

,702

($76

,146

)$1

,345

,556

$2

2,13

9,61

2

Oct

-17

$12,

987,

234

$212

,604

$1,3

06,1

65$1

4,50

6,00

3 $4

,834

,517

($21

,882

)$5

57,5

85$5

,370

,220

$1

,036

,399

($67

,161

)$9

69,2

39

$20,

845,

461

Nov

-17

$14,

042,

612

$461

,557

$1,5

97,6

68$1

6,10

1,83

6 $5

,332

,803

($13

3,86

4)$6

37,1

56$5

,836

,096

$1

,189

,003

($43

,984

)$1

,145

,019

$2

3,08

2,95

1

Dec

-17

$24,

255,

359

$553

,728

$4,6

27,1

37$2

9,43

6,22

4 $6

,279

,660

($14

1,58

3)$1

,708

,377

$7,8

46,4

54

$2,1

43,6

34($

37,2

33)

$2,1

06,4

01

$39,

389,

079

Tot

als

$179

,261

,339

$3

,935

,558

$1

9,06

8,25

2 $2

02,2

65,1

49

$64,

906,

645

($18

4,89

0)$7

,139

,714

$7

1,86

1,46

9 $1

6,25

2,99

9 ($

466,

762)

$15,

786,

237

$289

,912

,855

(a)

mon

thly

Sta

ndar

d O

ffer

Ser

vice

invo

ices

(b)

mon

thly

Sta

ndar

d O

ffer

Ser

vice

invo

ices

(c)

mon

thly

IS

O N

ew E

ngla

nd b

ills

(d)

Col

umn

(a)

+ C

olum

n (b

) +

Col

umn

(c)

(e)

Res

iden

tial

Col

umn

(d)

+ C

omm

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al C

olum

n (d

) +

Ind

ustr

ial C

olum

n (c

)

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ND

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ER

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ON

CIL

IAT

ION

For

the

Peri

od J

anua

ry 1

, 201

7 th

roug

h D

ecem

ber

31, 2

017

Exp

ense

Res

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tial

Com

mer

cial

Indu

stri

al


Section 1

Reconciliation Period: January 2015 through December 2015Recovery Period: April 2016 through March 2017Beginning Balance: $8,629,236, per Schedule ASC-2 Revised, Page 2, Docket No. 4599

Ending


Beginning Charge/ Ending Interest Interest Recovery

Month Balance (Refund) Balance Balance Rate Interest w/ Interest

(a) (b) (c) (d) (e) (f) (g)

Jan-16 $8,629,236 $8,629,236 $8,629,236 2.54% $18,265 $8,647,501

Feb-16 $8,647,501 $8,647,501 $8,647,501 2.54% $18,304 $8,665,805

Mar-16 $8,665,805 $8,665,805 $8,665,805 2.14% $15,454 $8,681,259

Apr-16 $8,681,259 ($276,026) $8,405,233 $8,543,246 2.14% $15,235 $8,420,468

May-16 $8,420,468 ($526,831) $7,893,637 $8,157,053 2.14% $14,547 $7,908,184

Jun-16 $7,908,184 ($677,996) $7,230,187 $7,569,185 2.14% $13,498 $7,243,686

Jul-16 $7,243,686 ($838,499) $6,405,187 $6,824,436 2.14% $12,170 $6,417,357

Aug-16 $6,417,357 ($1,027,547) $5,389,810 $5,903,584 2.14% $10,528 $5,400,338

Sep-16 $5,400,338 ($902,750) $4,497,588 $4,948,963 2.14% $8,826 $4,506,414

Oct-16 $4,506,414 ($626,935) $3,879,479 $4,192,946 2.14% $7,477 $3,886,956

Nov-16 $3,886,956 ($574,000) $3,312,957 $3,599,956 2.14% $6,420 $3,319,377

Dec-16 $3,319,377 ($660,974) $2,658,403 $2,988,890 2.14% $5,330 $2,663,733

Jan-17 $2,663,733 ($756,954) $1,906,779 $2,285,256 2.14% $4,075 $1,910,855

Feb-17 $1,910,855 ($698,440) $1,212,415 $1,561,635 2.14% $2,785 $1,215,200

Mar-17 $1,215,200 ($650,289) $564,911 $890,056 1.84% $1,365 $566,276

Apr-17 $566,276 ($371,337) $194,939 $380,607 1.84% $584 $195,522

Section 2

Reconciliation Period: January 2016 through December 2016

Recovery Period: April 2017 through March 2018

Beginning Balance: $12,126,489, per Schedule ASC-2 Revised, Page 2, Docket No. 4691

Ending




(a) (b) (c) (d) (e) (f) (g)

Jan-17 $12,126,489 $12,126,489 $12,126,489 2.14% $21,626 $12,148,114

Feb-17 $12,148,114 $12,148,114 $12,148,114 2.14% $21,664 $12,169,779

Mar-17 $12,169,779 $12,169,779 $12,169,779 1.84% $18,660 $12,188,439

Apr-17 $12,188,439 ($378,488) $11,809,951 $11,999,195 1.84% $18,399 $11,828,350

May-17 $11,828,350 ($796,315) $11,032,035 $11,430,192 1.84% $17,526 $11,049,561

Jun-17 $11,049,561 ($912,486) $10,137,075 $10,593,318 1.84% $16,243 $10,153,318

Jul-17 $10,153,318 ($1,254,452) $8,898,866 $9,526,092 1.84% $14,607 $8,913,473

Aug-17 $8,913,473 ($1,283,599) $7,629,874 $8,271,673 1.84% $12,683 $7,642,557

Sep-17 $7,642,557 ($1,094,869) $6,547,688 $7,095,123 1.84% $10,879 $6,558,567

Oct-17 $6,558,567 ($895,218) $5,663,350 $6,110,958 1.84% $9,370 $5,672,720

Nov-17 $5,672,720 ($902,892) $4,769,828 $5,221,274 1.84% $8,006 $4,777,834

Dec-17 $4,777,834 ($959,569) $3,818,265 $4,298,049 1.84% $6,590 $3,824,855

Jan-18 $3,824,855 ($1,271,985) $2,552,870 $3,188,863 1.84% $4,890 $2,557,759

Feb-18 $2,557,759 $0 $2,557,759 $2,557,759 1.84% $0 $2,557,759

Mar-18 $2,557,759 $0 $2,557,759 $2,557,759 2.33% $0 $2,557,759

Apr-18 $2,557,759 $2,557,759 $2,557,759 2.33% $0 $2,557,759

(a) Column (g) of previous row(b) Monthly revenue reports(c) Column (a) + Column (b)(d) (Column (a) + Column (c)] ÷ 2(e) Current Rate for Customer Deposits (f) [Column (d) x (Column (e)] ÷ 12(g) Column (c) + Column (f)


Status of Prior Period Reconciliation Amounts

Residential

Residential


Section 1

Reconciliation Period:Recovery Period:Beginning Balance:

Month

Jan-16

Feb-16

Mar-16

Apr-16

May-16

Jun-16

Jul-16

Aug-16

Sep-16

Oct-16

Nov-16

Dec-16

Jan-17

Feb-17

Mar-17

Apr-17

Section 2


Month

Jan-17

Feb-17

Mar-17

Apr-17

May-17

Jun-17

Jul-17

Aug-17

Sep-17

Oct-17

Nov-17

Dec-17

Jan-18

Feb-18

Mar-18

Apr-18

(a)(b)(c)(d)(e)(f)(g)

January 2015 through December 2015April 2016 through March 2017($2,021,026), per Schedule ASC-2 Revised, Page 3, Docket No. 4599

Ending



Balance (Refund) Balance Balance Rate Interest w/ Interest

(a) (b) (c) (d) (e) (f) (g)

($2,021,026) ($2,021,026) ($2,021,026) 2.54% ($4,278) ($2,025,304)

($2,025,304) ($2,025,304) ($2,025,304) 2.54% ($4,287) ($2,029,591)

($2,029,591) ($2,029,591) ($2,029,591) 2.14% ($3,619) ($2,033,211)

($2,033,211) $72,416 ($1,960,794) ($1,997,002) 2.14% ($3,561) ($1,964,356)

($1,964,356) $142,132 ($1,822,223) ($1,893,290) 2.14% ($3,376) ($1,825,600)

($1,825,600) $164,626 ($1,660,974) ($1,743,287) 2.14% ($3,109) ($1,664,082)

($1,664,082) $187,913 ($1,476,169) ($1,570,126) 2.14% ($2,800) ($1,478,969)

($1,478,969) $204,695 ($1,274,274) ($1,376,622) 2.14% ($2,455) ($1,276,729)

($1,276,729) $197,339 ($1,079,390) ($1,178,060) 2.14% ($2,101) ($1,081,491)

($1,081,491) $159,978 ($921,513) ($1,001,502) 2.14% ($1,786) ($923,299)

($923,299) $145,041 ($778,258) ($850,778) 2.14% ($1,517) ($779,775)

($779,775) $152,055 ($627,720) ($703,748) 2.14% ($1,255) ($628,975)

($628,975) $169,277 ($459,698) ($544,336) 2.14% ($971) ($460,668)

($460,668) $164,786 ($295,882) ($378,275) 2.14% ($675) ($296,557)

($296,557) $161,159 ($135,398) ($215,978) 1.84% ($331) ($135,729)

($135,729) $93,106 ($42,623) ($89,176) 1.84% ($137) ($42,760)


April 2017 through March 2018

$2,921,994, per Schedule ASC-2 Revised, Page 3, Docket No. 4691

Ending




(a) (b) (c) (d) (e) (f) (g)

$2,921,994 $2,921,994 $2,921,994 2.14% $5,211 $2,927,205

$2,927,205 $2,927,205 $2,927,205 2.14% $5,220 $2,932,425

$2,932,425 $2,932,425 $2,932,425 1.84% $4,496 $2,936,921

$2,936,921 ($98,183) $2,838,738 $2,887,830 1.84% $4,428 $2,843,166

$2,843,166 ($210,147) $2,633,019 $2,738,093 1.84% $4,198 $2,637,217

$2,637,217 ($233,730) $2,403,487 $2,520,352 1.84% $3,865 $2,407,352

$2,407,352 ($277,698) $2,129,654 $2,268,503 1.84% $3,478 $2,133,132

$2,133,132 ($281,078) $1,852,054 $1,992,593 1.84% $3,055 $1,855,109

$1,855,109 ($265,857) $1,589,252 $1,722,181 1.84% $2,641 $1,591,893

$1,591,893 ($237,563) $1,354,330 $1,473,111 1.84% $2,259 $1,356,588

$1,356,588 ($230,340) $1,126,248 $1,241,418 1.84% $1,904 $1,128,152

$1,128,152 ($227,042) $901,110 $1,014,631 1.84% $1,556 $902,666

$902,666 ($275,847) $626,819 $764,742 1.84% $1,173 $627,992

$627,992 $0 $627,992 $627,992 1.84% $0 $627,992

$627,992 $0 $627,992 $627,992 2.33% $0 $627,992

$627,992 $627,992 $627,992 2.33% $0 $627,992

Column (g) of previous rowMonthly revenue reportsColumn (a) + Column (b)(Column (a) + Column (c)] ÷ 2Current Rate for Customer Deposits [Column (d) x (Column (e)] ÷ 12Column (c) + Column (f)

Commercial

Commercial




Section 1


Month

Jan-16

Feb-16

Mar-16

Apr-16

May-16

Jun-16

Jul-16

Aug-16

Sep-16

Oct-16

Nov-16

Dec-16

Jan-17

Feb-17

Mar-17

Apr-17

Section 2


Month

Jan-17

Feb-17

Mar-17

Apr-17

May-17

Jun-17

Jul-17

Aug-17

Sep-17

Oct-17

Nov-17

Dec-17

Jan-18

Feb-18

Mar-18

Apr-18

(a)(b)(c)(d)(e)(f)(g)

January 2015 through December 2015April 2016 through March 2017$3,379,609, per Schedule ASC-2 Revised, Page 4, Docket No. 4599

Ending




(a) (b) (c) (d) (e) (f) (g)

$3,379,609 $3,379,609 $3,379,609 2.54% $7,154 $3,386,762

$3,386,762 $3,386,762 $3,386,762 2.54% $7,169 $3,393,931

$3,393,931 $3,393,931 $3,393,931 2.14% $6,053 $3,399,984

$3,399,984 ($81,160) $3,318,823 $3,359,404 2.14% $5,991 $3,324,814

$3,324,814 ($254,424) $3,070,390 $3,197,602 2.14% $5,702 $3,076,093

$3,076,093 ($209,906) $2,866,186 $2,971,139 2.14% $5,299 $2,871,485

$2,871,485 ($218,998) $2,652,487 $2,761,986 2.14% $4,926 $2,657,413

$2,657,413 ($220,008) $2,437,405 $2,547,409 2.14% $4,543 $2,441,948

$2,441,948 ($219,464) $2,222,484 $2,332,216 2.14% $4,159 $2,226,643

$2,226,643 ($215,712) $2,010,931 $2,118,787 2.14% $3,779 $2,014,709

$2,014,709 ($176,864) $1,837,846 $1,926,277 2.14% $3,435 $1,841,281

$1,841,281 ($175,564) $1,665,717 $1,753,499 2.14% $3,127 $1,668,844

$1,668,844 ($192,039) $1,476,805 $1,572,825 2.14% $2,805 $1,479,610

$1,479,610 ($176,738) $1,302,872 $1,391,241 2.14% $2,481 $1,305,353

$1,305,353 ($173,242) $1,132,111 $1,218,732 1.84% $1,869 $1,133,980

$1,133,980 ($112,829) $1,021,151 $1,077,566 1.84% $1,652 $1,022,803



$1,166,501, per Schedule ASC-2 Revised, Page 4, Docket No. 4691

Ending




(a) (b) (c) (d) (e) (f) (g)

$1,166,501 $1,166,501 $1,166,501 2.14% $2,080 $1,168,582

$1,168,582 $1,168,582 $1,168,582 2.14% $2,084 $1,170,666

$1,170,666 $1,170,666 $1,170,666 1.84% $1,795 $1,172,461

$1,172,461 ($38,352) $1,134,109 $1,153,285 1.84% $1,768 $1,135,877

$1,135,877 ($89,233) $1,046,645 $1,091,261 1.84% $1,673 $1,048,318

$1,048,318 ($93,475) $954,843 $1,001,580 1.84% $1,536 $956,379

$956,379 ($108,614) $847,765 $902,072 1.84% $1,383 $849,148

$849,148 ($110,874) $738,274 $793,711 1.84% $1,217 $739,491

$739,491 ($100,913) $638,578 $689,034 1.84% $1,057 $639,635

$639,635 ($117,728) $521,906 $580,771 1.84% $891 $522,797

$522,797 ($95,923) $426,874 $474,835 1.84% $728 $427,602

$427,602 ($89,535) $338,067 $382,834 1.84% $587 $338,654

$338,654 ($111,111) $227,543 $283,098 1.84% $434 $227,977

$227,977 $0 $227,977 $227,977 1.84% $0 $227,977

$227,977 $0 $227,977 $227,977 2.33% $0 $227,977

$227,977 $227,977 $227,977 2.33% $0 $227,977

Column (g) of previous rowMonthly revenue reportsColumn (a) + Column (b)(Column (a) + Column (c)] ÷ 2Current Rate for Customer Deposits [Column (d) x (Column (e)] ÷ 12Column (c) + Column (f)

Industrial

Industrial




Schedule A

SC-3




Schedule ASC-3

Calculation of Standard Offer Adjustment Factors

Standard Offer Service ReconciliationCalculation of SOS Adjustment Factors

Industrial Group SOS Adjustment Factor

(1) Industrial Group Over Recovery for the period January 1, 2017 through December 31, 2017 ($1,846,542)

(2) Interest During Refund Period ($31,042)

(3) Total Industrial Group SOS Over Collection ($1,877,584)

(4) forecasted Industrial Group SOS kWh for the period April 1, 2018 through March 31, 2019 249,842,034

(5) Industrial Group SOS Adjustment Factor ($0.00751)

Commercial Group SOS Adjustment Factor

(6) Commercial Group Under Recovery for the period January 1, 2017 through December 31, 2017 $1,183,668

(7) Interest During Recovery Period $19,898

(8) Total Commercial Group SOS Under Collection $1,203,566

(9) forecasted Commercial Group SOS kWh for the period April 1, 2018 through March 31, 2019 957,409,005

(10) Commercial Group SOS Adjustment Factor $0.00125

Residential Group SOS Adjustment Factor

(11) Residential Group Under Collection for the period January 1, 2017 through December 31, 2017 $4,716,617


(13) Total Residential Group SOS Under Collection $4,795,907

(14) forecasted Residential Group SOS kWh for the period April 1, 2018 through March 31, 2019 2,618,774,950

(15) Residential Group SOS Adjustment Factor $0.00183

(1) from Schedule ASC-2, Page 4, Ending Balance incl. Interest (9) Page 2, Line (4)(2) from Page 3 (10) Line (8) ÷ Line (9), truncated to five decimal places(3) Line (1) + Line (2) (11) from Schedule ASC-2, Page 2, Ending Balance incl. Interest(4) Page 2, Line (4) (12) from Page 3(5) Line (3) ÷ Line (4), truncated to five decimal places (13) Line (11) + Line (12)(6) from Schedule ASC-2, Page 3, Ending Balance incl. Interest (14) Page 2, Line (4)(7) from Page 3 (15) Line (13) ÷ Line (14), truncated to five decimal places(8) Line (6) + Line (7)


TotalRes Comm Ind Forecasted kWhs

Apr-2018 220,618,154 152,401,533 190,619,031 563,638,718 May-2018 197,691,605 146,661,064 184,855,152 529,207,821 Jun-2018 226,077,888 158,604,369 197,916,968 582,599,225 Jul-2018 288,942,818 174,265,961 218,276,281 681,485,060

Aug-2018 313,551,229 180,672,441 225,726,601 719,950,271 Sep-2018 275,723,738 173,665,507 215,920,037 665,309,283 Oct-2018 211,685,376 160,663,023 197,756,356 570,104,755

Nov-2018 201,168,881 149,846,373 185,822,711 536,837,964 Dec-2018 244,207,153 160,804,532 197,644,206 602,655,891 Jan-2019 276,441,428 167,755,511 205,135,259 649,332,198 Feb-2019 255,738,535 157,879,217 195,017,920 608,635,672 Mar-2019 240,370,533 152,643,340 189,891,356 582,905,229

Total 2,952,217,339 1,935,862,870 2,404,581,879 7,292,662,088

(1)

Jan 2018 % of SOS kWhs to Total kWhs 88.71% 49.46% 10.39%

(2) Jan18 SOS kWhs>> 273,522,306 92,328,097 21,915,401 (3) Jan18 Total kWhs>> 308,349,251 186,685,663 210,922,779

Res Comm IndTotal Forecasted SOS

kWhsApr-2018 195,700,123 75,372,384 19,805,791 290,878,298

May-2018 175,363,046 72,533,352 19,206,910 267,103,308 Jun-2018 200,543,199 78,440,086 20,564,065 299,547,351 Jul-2018 256,307,761 86,185,753 22,679,448 365,172,962

Aug-2018 278,136,739 89,354,171 23,453,555 390,944,465 Sep-2018 244,581,728 85,888,791 22,434,629 352,905,147 Oct-2018 187,776,270 79,458,224 20,547,377 287,781,870

Nov-2018 178,447,575 74,108,693 19,307,442 271,863,709 Dec-2018 216,624,829 79,528,209 20,535,724 316,688,762 Jan-2019 245,218,357 82,965,916 21,314,063 349,498,337 Feb-2019 226,853,782 78,081,452 20,262,847 325,198,081 Mar-2019 213,221,541 75,491,973 19,730,184 308,443,698

(4) Total 2,618,774,950 957,409,005 249,842,034 3,826,025,989

(1) Line (2) / Line (3)(2) Company revenue reports(3) Company revenue reports(4) Forecasted kWh x Line (1)

Calculation of Forecasted Standard Offer Deliveries for the Period of April 1, 2018 through March 31, 2019

Forecasted Total kWhs Apr 2018-Mar 2019:

Forecasted SOS kWhs Apr 2018-Mar2019:


Res

iden

tial

Com

mer

cial

Indu

stri

al

Beg

inni

ng(C

harg

e)/

End

ing

Inte

rest

Beg

inni

ng(C

harg

e)/

End

ing

Inte

rest

Beg

inni

ng(C

harg

e)/

End

ing

Inte

rest

Mon

thB

alan

ceR

efun

dB

alan

ceR

ate

Inte

rest

Mon

thB

alan

ceR

efun

dB

alan

ceR

ate

Inte

rest

Mon

thB

alan

ceR

efun

dB

alan

ceR

ate

Inte

rest

(1)

(2)

(3)

(4)

(5)

(1)

(2)

(3)

(4)

(5)

(1)

(2)

(3)

(4)

(5)

Jan-

18($

4,71

6,61

7)($

4,71

6,61

7)1.

84%

($7,

232)

Jan-

18($

1,18

3,66

8)($

1,18

3,66

8)1.

84%

($1,

815)

Jan-

18$1

,846

,542

$1,8

46,5

421.

84%

$2,8

31F

eb-1

8($

4,72

3,85

0)($

4,72

3,85

0)1.

84%

($7,

243)

Feb

-18

($1,

185,

483)

($1,

185,

483)

1.84

%($

1,81

8)F

eb-1

8$1

,849

,374

$1,8

49,3

741.

84%

$2,8

36M

ar-1

8($

4,73

1,09

3)($

4,73

1,09

3)2.

33%

($9,

186)

Mar

-18

($1,

187,

300)

($1,

187,

300)

2.33

%($

2,30

5)M

ar-1

8$1

,852

,209

$1,8

52,2

092.

33%

$3,5

96A

pr-1

8($

4,74

0,27

9)($

395,

023)

($4,

345,

256)

2.33

%($

8,82

1)A

pr-1

8($

1,18

9,60

6)($

99,1

34)

($1,

090,

472)

2.33

%($

2,21

4)A

pr-1

8$1

,855

,806

$154

,650

$1,7

01,1

552.

33%

$3,4

53M

ay-1

8($

4,35

4,07

6)($

395,

825)

($3,

958,

251)

2.33

%($

8,07

0)M

ay-1

8($

1,09

2,68

5)($

99,3

35)

($99

3,35

0)2.

33%

($2,

025)

May

-18

$1,7

04,6

09$1

54,9

64$1

,549

,644

2.33

%$3

,159

Jun-

18($

3,96

6,32

1)($

396,

632)

($3,

569,

689)

2.33

%($

7,31

6)Ju

n-18

($99

5,37

6)($

99,5

38)

($89

5,83

8)2.

33%

($1,

836)

Jun-

18$1

,552

,803

$155

,280

$1,3

97,5

232.

33%

$2,8

64Ju

l-18

($3,

577,

005)

($39

7,44

5)($

3,17

9,56

0)2.

33%

($6,

559)

Jul-

18($

897,

674)

($99

,742

)($

797,

932)

2.33

%($

1,64

6)Ju

l-18

$1,4

00,3

87$1

55,5

99$1

,244

,789

2.33

%$2

,568

Aug

-18

($3,

186,

120)

($39

8,26

5)($

2,78

7,85

5)2.

33%

($5,

800)

Aug

-18

($79

9,57

9)($

99,9

47)

($69

9,63

1)2.

33%

($1,

455)

Aug

-18

$1,2

47,3

57$1

55,9

20$1

,091

,437

2.33

%$2

,271

Sep

-18

($2,

793,

654)

($39

9,09

3)($

2,39

4,56

1)2.

33%

($5,

037)

Sep

-18

($70

1,08

7)($

100,

155)

($60

0,93

2)2.

33%

($1,

264)

Sep

-18

$1,0

93,7

08$1

56,2

44$9

37,4

642.

33%

$1,9

72O

ct-1

8($

2,39

9,59

8)($

399,

933)

($1,

999,

665)

2.33

%($

4,27

1)O

ct-1

8($

602,

196)

($10

0,36

6)($

501,

830)

2.33

%($

1,07

2)O

ct-1

8$9

39,4

36$1

56,5

73$7

82,8

632.

33%

$1,6

72N

ov-1

8($

2,00

3,93

6)($

400,

787)

($1,

603,

149)

2.33

%($

3,50

2)N

ov-1

8($

502,

901)

($10

0,58

0)($

402,

321)

2.33

%($

879)

Nov

-18

$784

,535

$156

,907

$627

,628

2.33

%$1

,371

Dec

-18

($1,

606,

651)

($40

1,66

3)($

1,20

4,98

8)2.

33%

($2,

730)

Dec

-18

($40

3,20

0)($

100,

800)

($30

2,40

0)2.

33%

($68

5)D

ec-1

8$6

28,9

99$1

57,2

50$4

71,7

492.

33%

$1,0

69Ja

n-19

($1,

207,

718)

($40

2,57

3)($

805,

145)

2.33

%($

1,95

4)Ja

n-19

($30

3,08

5)($

101,

028)

($20

2,05

7)2.

33%

($49

0)Ja

n-19

$472

,818

$157

,606

$315

,212

2.33

%$7

65F

eb-1

9($

807,

099)

($40

3,55

0)($

403,

550)

2.33

%($

1,17

5)F

eb-1

9($

202,

547)

($10

1,27

4)($

101,

274)

2.33

%($

295)

Feb

-19

$315

,977

$157

,989

$157

,989

2.33

%$4

60M

ar-1

9($

404,

725)

($40

4,72

5)$0

2.33

%($

393)

Mar

-19

($10

1,56

9)($

101,

569)

$02.

33%

($99

)M

ar-1

9$1

58,4

49$1

58,4

49$0

2.33

%$1

54

($79

,289

)($

19,8

98)

$31,

042

(1)

Jan-

18 p

er A

SC

-2, P

ages

2, 3

, and

4 e

ndin

g ba

lanc

es;

Feb

-18

thro

ugh

Mar

-19,

Col

umn

(3)

+ C

olum

n (5

) of

pre

viou

s m

onth

(2)

For

Apr

-201

8, (

Col

umn

(1))

÷ 1

2. F

or M

ay-2

018,

(C

olum

n (1

)) ÷

11,

etc

.(3

)C

olum

n (1

) -

Col

umn

(2)

(4)

Cur

rent

Rat

e fo

r C

usto

mer

Dep

osit

s (5

){[

Col

umn

(1)

+ C

olum

n (3

)] ÷

2}

x [C

olum

n (4

) ÷

12]

Cal

cula

tion

of In

tere

st D

urin

g R

ecov

ery/

Ref

und

Peri

odFo

r th

e St

anda

rd O

ffer

Ser

vice

Ove

r/U

nder

Rec

over

y In

curr

ed D

urin

g th

e Pe

riod

End

ing

Dec

embe

r 31

, 201

7


Schedule A

SC-4




Schedule ASC-4

Calculation of Standard Offer Service Administrative Cost Factors

CALCULATION OF STANDARD OFFER SERVICE ADMINISTRATIVE COST FACTORFor the Period April 1, 2018 through March 31, 2019

Total Residential Commercial Industrial

(1) Estimated Commodity Related Uncollectible Expense for 2018 $3,991,217 $2,794,888 $985,294 $211,035

(2) Estimated Other Administrative Expense for 2018 $2,284,480 $1,589,686 $571,144 $123,650

(3) Estimated Total Administrative Expense for 2018 $6,275,697 $4,384,574 $1,556,438 $334,685

(4) Forecasted SOS kWh for the period of April 1, 2018 through March 31, 2019 3,826,025,989 2,618,774,950 957,409,005 249,842,034

(5) Estimated SOS Administrative Cost Factor $0.00167 $0.00162 $0.00133

(6) SOS Administrative Cost Reconciliation Adjustment Factor ($0.00008) ($0.00003) $0.00029

(7) SOS Administrative Cost Factor effective April 1, 2018 $0.00159 $0.00159 $0.00162

(1) from Page 2, line (16)

(2) fom Page 3, line (4)

(3) Line 1 + Line 2

(4) per Schedule ASC-3, Page 2, Line (4)

(5) Line 3 ÷ Line 4, truncated to 5 decimal places

(6) per Schedule ASC-7, Page 1, Lines (5), (10), and (15)

(7) Line (5) + Line (6)


CALCULATION OF STANDARD OFFER SERVICE ADMINISTRATIVE COST FACTOR

Section 1: Estimated Commodity Cost/Revenue for April 1, 2018 through March 31, 2019

Residential Customer Group Commercial Customer Group Industrial Customer Group Total Estimated

Estimated Estimated Estimated Estimated Estimated Estimated Estimated Estimated Estimated SO

SO kWhs SO Rate SO Cost/Rev SO kWhs SO Rate SO Cost/Rev SO kWhs SO Rate SO Cost/Rev Cost/Revenue

(a) (b) (c)=(a) x (b) (d) (e) (f)=(d) x (e) (g) (h) (i)=(g) x (h) (j)= (c) + (f) + (i)

(1) Apr-2018 195,700,123 $0.08538 $16,708,876 75,372,384 $0.08233 $6,205,408 19,805,791 $0.05854 $1,159,431 $24,073,716

(2) May-2018 175,363,046 $0.08538 $14,972,497 72,533,352 $0.08233 $5,971,671 19,206,910 $0.05337 $1,025,073 $21,969,241

(3) Jun-2018 200,543,199 $0.08538 $17,122,378 78,440,086 $0.08233 $6,457,972 20,564,065 $0.06715 $1,380,877 $24,961,228

(4) Jul-2018 256,307,761 $0.08538 $21,883,557 86,185,753 $0.08233 $7,095,673 22,679,448 $0.06188 $1,403,404 $30,382,634

(5) Aug-2018 278,136,739 $0.08538 $23,747,315 89,354,171 $0.08233 $7,356,529 23,453,555 $0.06032 $1,414,718 $32,518,562

(6) Sep-2018 244,581,728 $0.08538 $20,882,388 85,888,791 $0.08233 $7,071,224 22,434,629 $0.05560 $1,247,365 $29,200,977

(7) Oct-2018 187,776,270 $0.08538 $16,032,338 79,458,224 $0.08233 $6,541,796 20,547,377 $0.04898 $1,006,411 $23,580,544

(8) Nov-2018 178,447,575 $0.08538 $15,235,854 74,108,693 $0.08233 $6,101,369 19,307,442 $0.05680 $1,096,663 $22,433,885

(9) Dec-2018 216,624,829 $0.08538 $18,495,428 79,528,209 $0.08233 $6,547,557 20,535,724 $0.07645 $1,569,956 $26,612,941

(10) Jan-2019 245,218,357 $0.08538 $20,936,743 82,965,916 $0.08233 $6,830,584 21,314,063 $0.10156 $2,164,656 $29,931,983

(11) Feb-2019 226,853,782 $0.08538 $19,368,776 78,081,452 $0.08233 $6,428,446 20,262,847 $0.09838 $1,993,459 $27,790,681

(12) Mar-2019 213,221,541 $0.08538 $18,204,855 75,491,973 $0.08233 $6,215,254 19,730,184 $0.07201 $1,420,771 $25,840,880

(13) Total 2,618,774,950 $223,591,005 957,409,005 $78,823,483 249,842,034 $16,882,784 $319,297,272

Section 2: Estimated Commodity-Related Uncollectible Expense for April 1, 2018 through March 31, 2019

(14) Estimated Rate Year Cost/Revenue $223,591,005 $78,823,483 $16,882,784 $319,297,272

(15) Uncollectible Rate 1.25% 1.25% 1.25%

(16)

$2,794,888 $985,294 $211,035 $3,991,217

Section 1:

Columns (a), (d) and (g), Lines (1) through (12) = Schedule ASC-3, Page 2, Line (4)

Section 2:

(14) Line (13)

(15) SOS uncollectible rate approved in Docket No. 4323

(16) Line (14) x Line (15)

Rate Year Commodity-Related Uncollectible Expense

Column (h): the sum of the proposed April 1, 2018 through June 30, 2018 base Standard Offer rates (Docket No. 4692, filed January 18, 2017, Attachment 1, Page 3, Line (10), Column (g)), the current 2017 RES rate of 0.04¢, and the proposed SOS Adjustment charge of (0.751¢). The July-2017 through Mar-2018 estimated SOS Base charges are based on the actual July-2016 through Mar-2017 SOS base charges

Column (b): the sum of the proposed April 1, 2018 base Standard Offer rate of 8.315¢ (Docket No. 4692, filed January 18, 2018, Attachment 1, Page 3, Line (10), Column (g)), the current 2017 RES rate of 0.04¢, and the proposed SOS Adjustment charge of 0.183¢

Column (e): the sum of the proposed April 1, 2018 base Standard Offer rate of 6.298¢ (Docket No. 4692, filed January 18, 2018, Attachment 1, Page 4, Line (10), Column (g)), the current 2017 RES rate of 0.04¢, and the proposed SOS Adjustment charge of 0.125¢

For the Period April 1, 2018 through March 31, 2019


CALCULATION OF STANDARD OFFER SERVICE ADMINISTRATIVE COST FACTORFor the Period April 1, 2018 through March 31, 2019

Total Residential Commercial Industrial

(1) Estimated GIS Cost $38,035 $26,421 $9,527 $2,087

(2) Estimated CWC $1,994,012 $1,388,438 $498,005 $107,569

(3) Estimate of Other Administrative Costs $252,433 $174,827 $63,612 $13,994

(4) Total Other Administrative Expenses $2,284,480 $1,589,686 $571,144 $123,650

(1) from Schedule ASC-5, Page 6, column (g), Schedule ASC-5, Page 7, column (g) and Schedule ASC-5, Page 8, column (g)(2) from Schedule ASC-6, Page 2, Lines (15), (14), and (13)(3) from Schedule ASC-5, Page 6, column (i), Schedule ASC-5, Page 7, column (i) and Schedule ASC-5, Page 8, column (i)(4) Line (1) + Line (2) + Line (3)


Schedule ASC

-5




Schedule ASC-5

Standard Offer Service Administrative Cost Adjustment Reconciliation For the period January 2017 through December 2017

STANDARD OFFER SERVICE ADMINISTRATIVE COST RECONCILIATION

Over/(Under) SOS SOS Over/(Under)

Beginning Admin. Cost Admin. Cost Monthly Ending


(a) (b) (c) (d) (e)

(1) Jan-17 $0 $461,545 $368,802 $92,743 $92,743

Feb-17 $92,743 $650,386 $560,298 $90,088 $182,830

Mar-17 $182,830 $615,478 $530,879 $84,599 $267,430

Apr-17 $267,430 $554,561 $479,953 $74,608 $342,037

May-17 $342,037 $395,494 $399,446 ($3,952) $338,085

Jun-17 $338,085 $443,378 $429,917 $13,461 $351,547

Jul-17 $351,547 $582,539 $512,969 $69,570 $421,117

Aug-17 $421,117 $593,670 $527,509 $66,161 $487,278

Sep-17 $487,278 $522,319 $493,680 $28,639 $515,917

Oct-17 $515,917 $444,712 $477,749 ($33,037) $482,880

Nov-17 $482,880 $437,721 $535,519 ($97,798) $385,082

Dec-17 $385,082 $453,285 $556,523 ($103,237) $281,845

(2) Jan-18 $281,845 $329,214 $204,331 $124,883 $406,728

Subtotal $0 $6,484,301 $6,077,573 $406,728 $406,728


(4) Ending Balance Prior to Application of Interest $193,240

(5) Interest $1,826

(6) Ending Balance Including Interest $195,066



(3) Pages 9, 10 and 11, Section 1, Column (g)

(4) Column (e) Ending Balance + Line (3)


(6) Line (4) + Line (5)


(b) Per pages 2, 3 and 4 sum of column (b) for Residential, Commercial and Industrial customer groups

(c) Per pages 2, 3 and 4, sum of column (c) for Residential, Commercial and Industrial customer groups



BASE RECONCILIATION - ALL CUSTOMER GROUPS

For the Period January 1, 2017 through December 31, 2017






(a) (b) (c) (d) (e)

(1) Jan-17 $0 $322,773 $253,345 $69,428 $69,428

Feb-17 $69,428 $448,045 $378,603 $69,442 $138,870

Mar-17 $138,870 $417,217 $361,147 $56,069 $194,939

Apr-17 $194,939 $379,008 $333,954 $45,055 $239,994

May-17 $239,994 $267,946 $278,166 ($10,220) $229,774

Jun-17 $229,774 $304,249 $299,617 $4,632 $234,406

Jul-17 $234,406 $418,292 $358,338 $59,954 $294,360

Aug-17 $294,360 $427,796 $367,095 $60,701 $355,061

Sep-17 $355,061 $365,064 $338,877 $26,187 $381,248

Oct-17 $381,248 $298,457 $328,404 ($29,947) $351,301

Nov-17 $351,301 $301,067 $379,473 ($78,406) $272,894

Dec-17 $272,894 $319,915 $395,417 ($75,502) $197,393

(2) Jan-18 $197,393 $237,792 $146,136 $91,656 $289,048

Subtotal $0 $4,507,621 $4,218,573 $289,048 $289,048


(4) Ending Balance Prior to Application of Interest $227,505

(5) Interest $2,150

(6) Ending Balance Including Interest $229,655

(1) Reflects revenues based on kWhs consumed after January 1(2) Reflects revenues based on kWhs consumed prior to January 1(3) Final values on Page 9, Section 1, column (g) (4) Column (e) Ending Balance+ Line (3)(5) [(Beginning balance + Ending balance) ÷ 2] x [(2.14% x 2/12)+(1.84% x 10/12)](6) Line (4) + Line(5)

(a) Column (e) from previous row(b) Page 5 Column (c) for Residential(c) Page 6 Column (j)(d) Column (b) - Column (c)(e) Column (a) + Column (d)

Residential


Reconciliation By Customer Group


Month

(1) Jan-17

Feb-17

Mar-17

Apr-17

May-17

Jun-17

Jul-17

Aug-17

Sep-17

Oct-17

Nov-17

Dec-17

(2) Jan-18

Subtotal

(3)

(4)

(5)

(6)

(1)(2)(3)(4)(5)(6)

(a)(b)(c)(d)(e)



Balance Revenue Expense Over/(Under) Balance

(a) (b) (c) (d) (e)

$0 $104,998 $95,475 $9,523 $9,523

$9,523 $164,015 $151,539 $12,477 $22,000

$22,000 $160,309 $142,439 $17,870 $39,870

$39,870 $140,119 $121,858 $18,261 $58,131

$58,131 $103,275 $99,598 $3,677 $61,808

$61,808 $113,871 $107,959 $5,912 $67,720

$67,720 $134,897 $127,298 $7,599 $75,319

$75,319 $135,938 $130,906 $5,032 $80,351

$80,351 $129,987 $127,105 $2,882 $83,233

$83,233 $114,442 $121,534 ($7,092) $76,141

$76,141 $110,734 $131,423 ($20,689) $55,452

$55,452 $109,064 $134,493 ($25,429) $30,024

$30,024 $74,588 $48,360 $26,228 $56,251

$0 $1,596,237 $1,539,986 $56,251 $56,251

Remaining Balance from Over(Under) Recovery incurred during 2015 ($19,365)

Ending Balance Prior to Application of Interest $36,886

Interest $349

Ending Balance Including Interest $37,235

Reflects revenues based on kWhs consumed after January 1Reflects revenues based on kWhs consumed prior to January 1Final values on Page 10, Section 1, column (g) Column (e) Ending Balance+ Line (3)[(Beginning balance + Ending balance) ÷ 2] x [(2.14% x 2/12)+(1.84% x 10/12)]Line (4) + Line(5)

Column (e) from previous rowPage 5 Column (c) for CommercialPage 7 Column (j)Column (b) - Column (c)Column (a) + Column (d)

Commercial





Month

(1) Jan-17

Feb-17

Mar-17

Apr-17

May-17

Jun-17

Jul-17

Aug-17

Sep-17

Oct-17

Nov-17

Dec-17

(2) Jan-18

Subtotal

(3)

(4)

(5)

(6)

(1)(2)(3)(4)(5)(6)

(a)(b)(c)(d)(e)



Balance Revenue Expense Over/(Under) Balance

(a) (b) (c) (d) (e)

$0 $33,774 $19,982 $13,792 $13,792

$13,792 $38,326 $30,157 $8,169 $21,961

$21,961 $37,952 $27,293 $10,659 $32,620

$32,620 $35,434 $24,142 $11,292 $43,912

$43,912 $24,273 $21,681 $2,591 $46,503

$46,503 $25,259 $22,341 $2,917 $49,421

$49,421 $29,349 $27,332 $2,017 $51,438

$51,438 $29,936 $29,508 $428 $51,866

$51,866 $27,268 $27,698 ($430) $51,436

$51,436 $31,812 $27,811 $4,002 $55,438

$55,438 $25,920 $24,622 $1,298 $56,736

$56,736 $24,306 $26,613 ($2,307) $54,429

$54,429 $16,835 $9,835 $6,999 $61,428

$380,443 $319,015 $61,428 $61,428

Remaining Balance from Over(Under) Recovery incurred during 2015 ($132,579)

Ending Balance Prior to Application of Interest ($71,151)

Interest ($672)

Ending Balance Including Interest ($71,824)

Reflects revenues based on kWhs consumed after January 1Reflects revenues based on kWhs consumed prior to January 1Final values on Page 11, Section 1, column (g) Column (e) Ending Balance+ Line (3)[(Beginning balance + Ending balance) ÷ 2] x [(2.14% x 2/12)+(1.84% x 10/12)]Line (4) + Line(5)

Column (e) from previous rowPage 5 Column (c) for CommercialPage 8 Column (j)Column (b) - Column (c)Column (a) + Column (d)

Industrial

STANDARD OFFER SERVICE ADMINISTRATIVE COST RECONCILIATIONFor the Period January 1, 2017 through December 31, 2017



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Jan-

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22,7

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29,9

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$329

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$15,

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$102

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$95,

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$87,

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$696

$47,

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$5,2

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$68,

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95$4

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$99,

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17$4

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$55,

340

$632

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19$1

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59

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17$6

,087

,589

($27

7,69

8)$1

12,5

94$3

7,62

6$5

,960

,112

$74,

501

$1,2

66$4

7,76

7$3

,763

$127

,298

A

ug-1

7$6

,206

,605

($28

1,07

8)$1

13,4

98$3

7,58

8$6

,076

,612

$75,

958

$952

$47,

767

$6,2

29$1

30,9

06

Sep

-17

$5,8

24,6

14($

265,

857)

$108

,582

$36,

645

$5,7

03,9

83$7

1,30

0$8

61$4

7,76

7$7

,176

$127

,105

O

ct-1

7$5

,564

,846

($23

7,56

3)$9

5,43

5$3

1,25

5$5

,453

,973

$68,

175

$870

$47,

767

$4,7

21$1

21,5

34

Nov

-17

$6,3

20,3

74($

230,

340)

$92,

315

$30,

201

$6,2

12,5

49$7

7,65

7$6

43$4

7,76

7$5

,356

$131

,423

D

ec-1

7$6

,686

,752

($22

7,04

2)$9

0,81

0$2

9,60

4$6

,580

,125

$82,

252

$515

$47,

767

$3,9

59$1

34,4

93

(2)

Jan-

18$3

,946

,550

($16

1,26

0)$6

2,16

4$2

1,35

4$3

,868

,808

$48,

360

$48,

360

Tot

als

$70,

645,

784

($1,

730,

486)

$1,5

90,2

93

$985

,423

$7

1,49

1,01

4 $8

93,6

38

$9,5

27

$573

,209

$6

3,61

2 $1

,539

,986

(1)R

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SO

SS

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Ene

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Sta

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olle

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Rev

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Rev

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Adj

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Rev

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Rev

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Exp

ense

GIS

C

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Adm

inT

otal

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(1)

Jan-

17$2

,136

,450

($83

,227

)$4

4,63

0$2

3,63

8$2

,121

,492

$8,2

47$1

93$1

0,31

8$1

,224

$19,

982

Feb

-17

$1,5

03,9

91($

176,

738)

$61,

799

$48,

964

$1,4

38,0

16$1

7,97

5$1

76$1

0,31

8$1

,688

$30,

157

Mar

-17

$1,3

02,9

65($

173,

242)

$62,

109

$50,

439

$1,2

42,2

71$1

5,52

8$1

35$1

0,31

8$1

,312

$27,

293

Apr

-17

$1,0

77,4

01($

151,

181)

$49,

237

$35,

184

$1,0

10,6

41$1

2,63

3$1

82$1

0,31

8$1

,009

$24,

142

May

-17

$857

,569

($89

,233

)$2

1,65

7$7

,374

$797

,367

$9,9

67$1

97$1

0,31

8$1

,200

$21,

681

Jun-

17$9

56,6

70($

93,4

75)

$22,

493

$7,3

75$8

93,0

63$1

1,16

3$1

12$1

0,31

8$7

48$2

2,34

1 Ju

l-17

$1,3

53,0

23($

108,

614)

$26,

136

$8,5

69$1

,279

,114

$15,

989

$258

$10,

318

$767

$27,

332

Aug

-17

$1,4

88,5

12($

110,

874)

$26,

680

$8,7

47$1

,413

,065

$17,

663

$202

$10,

318

$1,3

25$2

9,50

8 S

ep-1

7$1

,301

,724

($10

0,91

3)$2

4,28

3$7

,962

$1,2

33,0

56$1

5,41

3$2

11$1

0,31

8$1

,756

$27,

698

Oct

-17

$1,3

98,7

97($

117,

728)

$28,

329

$9,2

88$1

,318

,687

$16,

484

$157

$10,

318

$852

$27,

811

Nov

-17

$1,1

15,4

81($

95,9

23)

$23,

082

$7,5

68$1

,050

,208

$13,

128

$126

$10,

318

$1,0

51$2

4,62

2 D

ec-1

7$1

,268

,443

($89

,535

)$2

1,54

5$7

,064

$1,2

07,5

17$1

5,09

4$1

38$1

0,31

8$1

,063

$26,

613

(2)

Jan-

18$8

31,6

64($

64,9

56)

$14,

991

$5,1

25$7

86,8

24$9

,835

$9,8

35

Tot

als

$16,

592,

690

($1,

455,

638)

$426

,971

$2

27,2

96

$15,

791,

319

$179

,120

$2

,087

$1

23,8

13

$13,

994

$319

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31, 2

017


Section 1



Beginning Balance: ($2,366,898), per Schedule ASC-5 Revised, Page 2, Docket No. 4599

Over/(Under)

Over(Under) Ending

Beginning Charge Ending Interest Interest Recovery


(a) (b) (c) (d) (e) (f) (g)

Jan-16 ($2,366,898) ($2,366,898) ($2,366,898) 2.54% ($5,010) ($2,371,908)

Feb-16 ($2,371,908) ($2,371,908) ($2,371,908) 2.54% ($5,021) ($2,376,928)

Mar-16 ($2,376,928) ($2,376,928) ($2,376,928) 2.14% ($4,239) ($2,381,167)

Apr-16 ($2,381,167) $72,158 ($2,309,010) ($2,345,088) 2.14% ($4,182) ($2,313,192)

May-16 ($2,313,192) $144,807 ($2,168,384) ($2,240,788) 2.14% ($3,996) ($2,172,380)

Jun-16 ($2,172,380) $185,714 ($1,986,667) ($2,079,524) 2.14% ($3,708) ($1,990,375)

Jul-16 ($1,990,375) $229,443 ($1,760,932) ($1,875,653) 2.14% ($3,345) ($1,764,277)

Aug-16 ($1,764,277) $281,173 ($1,483,103) ($1,623,690) 2.14% ($2,896) ($1,485,999)

Sep-16 ($1,485,999) $247,162 ($1,238,837) ($1,362,418) 2.14% ($2,430) ($1,241,266)

Oct-16 ($1,241,266) $171,639 ($1,069,628) ($1,155,447) 2.14% ($2,061) ($1,071,688)Nov-16 ($1,071,688) $156,987 ($914,701) ($993,194) 2.14% ($1,771) ($916,472)

Dec-16 ($916,472) $180,993 ($735,479) ($825,975) 2.14% ($1,473) ($736,952)

Jan-17 ($736,952) $207,188 ($529,764) ($633,358) 2.14% ($1,129) ($530,894)

Feb-17 ($530,894) $191,148 ($339,746) ($435,320) 2.14% ($776) ($340,522)

Mar-17 ($340,522) $177,945 ($162,578) ($251,550) 1.84% ($386) ($162,963)

Apr-17 ($162,963) $101,592 ($61,371) ($112,167) 1.84% ($172) ($61,543)

Section 2



Beginning Balance: $194,094, per Schedule ASC-5, Page 2, Docket No. 4691

Over/(Under)

Over(Under) Ending



(a) (b) (c) (d) (e) (f) (g)

Jan-17 $194,094 $194,094 $194,094 2.14% $346 $194,440

Feb-17 $194,440 $194,440 $194,440 2.14% $347 $194,787

Mar-17 $194,787 $194,787 $194,787 1.84% $299 $195,086

Apr-17 $195,086 ($5,868) $189,217 $192,151 1.84% $295 $189,512

May-17 $189,512 ($12,020) $177,492 $183,502 1.84% $281 $177,773

Jun-17 $177,773 ($13,737) $164,036 $170,905 1.84% $262 $164,298

Jul-17 $164,298 ($18,888) $145,410 $154,854 1.84% $237 $145,648

Aug-17 $145,648 ($19,322) $126,326 $135,987 1.84% $209 $126,534

Sep-17 $126,534 ($16,486) $110,049 $118,292 1.84% $181 $110,230

Oct-17 $110,230 ($13,480) $96,750 $103,490 1.84% $159 $96,909

Nov-17 $96,909 ($13,596) $83,312 $90,110 1.84% $138 $83,450

Dec-17 $83,450 ($14,440) $69,011 $76,230 1.84% $117 $69,127

Jan-18 $69,127 ($19,147) $49,981 $59,554 1.84% $91 $50,072

Feb-18 $50,072 $0 $50,072 $50,072 1.84% $77 $50,149

Mar-18 $50,149 $0 $50,149 $50,149 2.33% $97 $50,246

Apr-18 $50,246 $0 $50,246 $50,246 2.33% $98 $50,344

(a) January 2017, per Schedule ASC-5, page 2, Line (5), remaining months Column (g) of previous row(b) Page 12, Column (b)(c) Column (a) + Column (b)(d) (Column (a) + Column (c)] ÷ 2(e) Current Rate for Customer Deposits (f) Column (d) x (Column (e) ÷ 12)(g) Column (c) + Column (f)


Residential

Residential

Standard Offer Service Administrative Cost Adjustment Prior Period Over/(Under) Recovery


Section 1


Month

Jan-16

Feb-16

Mar-16

Apr-16

May-16

Jun-16

Jul-16

Aug-16

Sep-16

Oct-16Nov-16

Dec-16

Jan-17

Feb-17

Mar-17

Apr-17

Section 2


Month

Jan-17

Feb-17

Mar-17

Apr-17

May-17

Jun-17

Jul-17

Aug-17

Sep-17

Oct-17

Nov-17

Dec-17

Jan-18

Feb-18

Mar-18

Apr-18

(a)(b)(c)(d)(e)(f)(g)



($720,030), per Schedule ASC-5 Revised, Page 2, Docket No. 4599

Over/(Under)

Over(Under) Ending



(a) (b) (c) (d) (e) (f) (g)

($720,030) ($720,030) ($720,030) 2.54% ($1,524) ($721,554)

($721,554) ($721,554) ($721,554) 2.54% ($1,527) ($723,081)

($723,081) ($723,081) ($723,081) 2.14% ($1,290) ($724,371)

($724,371) $25,437 ($698,934) ($711,653) 2.14% ($1,269) ($700,203)

($700,203) $50,366 ($649,837) ($675,020) 2.14% ($1,204) ($651,041)

($651,041) $58,384 ($592,657) ($621,849) 2.14% ($1,109) ($593,766)

($593,766) $66,588 ($527,178) ($560,472) 2.14% ($1,000) ($528,178)

($528,178) $72,477 ($455,701) ($491,939) 2.14% ($877) ($456,578)

($456,578) $69,953 ($386,626) ($421,602) 2.14% ($752) ($387,378)

($387,378) $56,705 ($330,672) ($359,025) 2.14% ($640) ($331,313)($331,313) $51,372 ($279,941) ($305,627) 2.14% ($545) ($280,486)

($280,486) $53,881 ($226,605) ($253,545) 2.14% ($452) ($227,057)

($227,057) $59,974 ($167,083) ($197,070) 2.14% ($351) ($167,435)

($167,435) $58,400 ($109,034) ($138,234) 2.14% ($247) ($109,281)

($109,281) $57,100 ($52,180) ($80,731) 1.84% ($124) ($52,304)

($52,304) $32,994 ($19,310) ($35,807) 1.84% ($55) ($19,365)



$235,708, per Schedule ASC-5, Page 2, Docket No. 4691

Over/(Under)

Over(Under) Ending



(a) (b) (c) (d) (e) (f) (g)

$235,708 $235,708 $235,708 2.14% $420 $236,128

$236,128 $236,128 $236,128 2.14% $421 $236,549

$236,549 $236,549 $236,549 1.84% $363 $236,912

$236,912 ($7,787) $229,125 $233,018 1.84% $357 $229,482

$229,482 ($17,499) $211,983 $220,733 1.84% $338 $212,322

$212,322 ($19,813) $192,508 $202,415 1.84% $310 $192,819

$192,819 ($22,303) $170,516 $181,667 1.84% $279 $170,794

$170,794 ($22,440) $148,354 $159,574 1.84% $245 $148,599

$148,599 ($21,405) $127,194 $137,896 1.84% $211 $127,405

$127,405 ($19,007) $108,398 $117,902 1.84% $181 $108,579

$108,579 ($18,419) $90,160 $99,370 1.84% $152 $90,313

$90,313 ($18,254) $72,058 $81,186 1.84% $124 $72,183

$72,183 ($22,159) $50,024 $61,104 1.84% $94 $50,118

$50,118 $0 $50,118 $50,118 1.84% $77 $50,195

$50,195 $0 $50,195 $50,195 2.33% $97 $50,292

$50,292 $0 $50,292 $50,292 2.33% $98 $50,390

January 2017, per Schedule ASC-5, page 2, Line (5), remaining months Column (g) of previous rowPage 12, Column (b)Column (a) + Column (b)(Column (a) + Column (c)] ÷ 2Current Rate for Customer Deposits Column (d) x (Column (e) ÷ 12)Column (c) + Column (f)

For the Period January 1, 2017 through December 31, 2017STANDARD OFFER SERVICE ADMINISTRATIVE COST RECONCILIATION

Commercial

Commercial



Section 1


Month

Jan-16

Feb-16

Mar-16

Apr-16

May-16

Jun-16

Jul-16

Aug-16

Sep-16

Oct-16Nov-16

Dec-16

Jan-17

Feb-17

Mar-17

Apr-17

Section 2


Month

Jan-17

Feb-17

Mar-17

Apr-17

May-17

Jun-17

Jul-17

Aug-17

Sep-17

Oct-17

Nov-17

Dec-17

Jan-18

Feb-18

Mar-18

Apr-18

(a)(b)(c)(d)(e)(f)(g)



($461,638), per Schedule ASC-5 Revised, Page 2, Docket No. 4599

Over/(Under)

Over(Under) Ending



(a) (b) (c) (d) (e) (f) (g)

($461,638) ($461,638) ($461,638) 2.54% ($977) ($462,615)

($462,615) ($462,615) ($462,615) 2.54% ($979) ($463,594)

($463,594) ($463,594) ($463,594) 2.14% ($827) ($464,421)

($464,421) $18,421 ($446,000) ($455,210) 2.14% ($812) ($446,811)

($446,811) $34,856 ($411,956) ($429,383) 2.14% ($766) ($412,721)

($412,721) $29,657 ($383,064) ($397,893) 2.14% ($710) ($383,774)

($383,774) $29,804 ($353,969) ($368,872) 2.14% ($658) ($354,627)

($354,627) $29,837 ($324,790) ($339,709) 2.14% ($606) ($325,396)

($325,396) $29,836 ($295,560) ($310,478) 2.14% ($554) ($296,114)

($296,114) $29,357 ($266,756) ($281,435) 2.14% ($502) ($267,258)($267,258) $24,070 ($243,188) ($255,223) 2.14% ($455) ($243,643)

($243,643) $23,893 ($219,750) ($231,697) 2.14% ($413) ($220,163)

($220,163) $26,135 ($194,028) ($207,095) 2.14% ($369) ($194,397)

($194,397) $23,473 ($170,924) ($182,660) 2.14% ($326) ($171,250)

($171,250) $24,157 ($147,092) ($159,171) 1.84% ($244) ($147,336)

($147,336) $14,972 ($132,365) ($139,851) 1.84% ($214) ($132,579)



$35,429, per Schedule ASC-5, Page 2, Docket No. 4691

Over/(Under)

Over(Under) Ending



(a) (b) (c) (d) (e) (f) (g)

$35,429 $35,429 $35,429 2.14% $63 $35,492

$35,492 $35,492 $35,492 2.14% $63 $35,555

$35,555 $35,555 $35,555 1.84% $55 $35,610

$35,610 ($1,168) $34,442 $35,026 1.84% $54 $34,495

$34,495 ($2,616) $31,879 $33,187 1.84% $51 $31,930

$31,930 ($2,766) $29,165 $30,548 1.84% $47 $29,212

$29,212 ($3,213) $25,998 $27,605 1.84% $42 $26,041

$26,041 ($3,257) $22,784 $24,412 1.84% $37 $22,821

$22,821 ($2,986) $19,836 $21,329 1.84% $33 $19,869

$19,869 ($3,483) $16,385 $18,127 1.84% $28 $16,413

$16,413 ($2,838) $13,575 $14,994 1.84% $23 $13,598

$13,598 ($2,761) $10,837 $12,218 1.84% $19 $10,856

$10,856 ($3,287) $7,569 $9,213 1.84% $14 $7,583

$7,583 $0 $7,583 $7,583 1.84% $12 $7,595

$7,595 $0 $7,595 $7,595 2.33% $15 $7,609

$7,609 $0 $7,609 $7,609 2.33% $15 $7,624

January 2017, per Schedule ASC-5, page 2, Line (5), remaining months Column (g) of previous rowPage 12, Column (b)Column (a) + Column (b)(Column (a) + Column (c)] ÷ 2Current Rate for Customer Deposits Column (d) x (Column (e) ÷ 12)Column (c) + Column (f)



Industrial

Industrial


Section 1.



Approved Factor: $0.00087 $0.00073 $0.00138

Residential Residential Commercial Commercial Industrial Industrial

Group Adj Factor Group Adj Factor Group Adj Factor

Month SOS kWhs Revenue SOS kWhs Revenue SOS kWhs Revenue

(a) (b) (a) (b) (a) (b)

(1) Apr-16 82,939,883 $72,158 34,844,764 $25,437 13,348,869 $18,421

May-16 166,445,212 $144,807 68,994,928 $50,366 25,257,862 $34,856

Jun-16 213,464,192 $185,714 79,977,916 $58,384 21,490,629 $29,657

Jul-16 263,728,031 $229,443 91,215,824 $66,588 21,597,411 $29,804

Aug-16 323,187,899 $281,173 99,283,079 $72,477 21,621,241 $29,837

Sep-16 284,094,258 $247,162 95,825,524 $69,953 21,620,124 $29,836

Oct-16 197,285,996 $171,639 77,678,425 $56,705 21,273,358 $29,357

Nov-16 180,445,380 $156,987 70,372,620 $51,372 17,442,183 $24,070

Dec-16 208,037,873 $180,993 73,809,492 $53,881 17,313,963 $23,893

Jan-17 238,146,788 $207,188 82,156,001 $59,974 18,938,756 $26,135

Feb-17 219,709,824 $191,148 80,000,260 $58,400 17,009,557 $23,473

Mar-17 204,534,283 $177,945 78,219,734 $57,100 17,505,203 $24,157

(2) Apr-17 116,772,623 $101,592 45,197,049 $32,994 10,848,962 $14,972

(a) from Company reports(b) Column (a) x SOS Admin. Cost Reconciliation Adj. Factor per RIPUC Docket No. 4599, Schedule ASC-4 Revised, Page 1, lin

Section 2.



Approved Factor: ($0.00007) ($0.00024) ($0.00015)

Residential Residential Commercial Commercial Industrial Industrial

Group Adj Factor Group Adj Factor Group Adj Factor

Month SOS kWhs Revenue SOS kWhs Revenue SOS kWhs Revenue

(c) (d) (c) (d) (c) (d)

(1) Apr-17 83,833,154 ($5,868) 32,447,770 ($7,787) 7,788,664 ($1,168)

May-17 171,715,597 ($12,020) 72,911,975 ($17,499) 17,439,777 ($2,616)

Jun-17 196,244,614 ($13,737) 82,554,553 ($19,813) 18,436,866 ($2,766)

Jul-17 269,824,568 ($18,888) 92,929,923 ($22,303) 21,422,861 ($3,213)

Aug-17 276,027,812 ($19,322) 93,500,858 ($22,440) 21,710,458 ($3,257)

Sep-17 235,509,895 ($16,486) 89,186,794 ($21,405) 19,903,848 ($2,986)

Oct-17 192,573,015 ($13,480) 79,195,636 ($19,007) 23,220,557 ($3,483)

Nov-17 194,232,887 ($13,596) 76,745,667 ($18,419) 18,919,757 ($2,838)

Dec-17 206,284,947 ($14,440) 76,058,706 ($18,254) 18,405,425 ($2,761)

Jan-18 273,522,497 ($19,147) 92,328,097 ($22,159) 21,915,401 ($3,287)

Feb-18 - $0 - $0 - $0

Mar-18 - $0 - $0 - $0

(2) Apr-18 - $0 - $0 - $0

(c) From Company reports(d) Column (a) x SOS Admin. Cost Reconciliation Adj. Factor per RIPUC Docket No. 4691, Schedule ASC-4, Page 1, line (6)

(1) Reflects usage after April 1

(2) Reflects usage prior to April 1



Residential Commercial Industrial


Residential Commercial Industrial

Calculation of Standard Offer Service Admin. Cost Adj. Factor Revenue


Schedule A

SC-6




Schedule ASC-6

Cash Working Capital Analysis

Narragansett Electric Company


Calendar Year 2017

Customer Working

Days of Annual Payment Capital

Cost Percent Lag % CWC % Expense Requirement

(a) (b) (c) (d) (e) (f)

(1) 2017 Purchase Power Costs/Working Capital Requirement (21.853) -5.99% 12.82% 6.83% $289,018,509 $19,739,964

(2) Gross Receipts Tax 76.45 20.95% 12.82% 33.77% $11,686,003 $3,946,363

(3) Total $23,686,328

(4) Interest Rate 9.68%

(5) Working Capital Impact $2,292,837

(6) Standard Offer Service Revenue - Industrial Group $15,172,290

(7) Standard Offer Service Revenue - Commercial Group $70,652,820

(8) Standard Offer Service Revenue - Residential Group $197,208,886

(9) Standard Offer Service Revenue - Total $283,033,996

(10) Percentage of Standard Offer Expenses attributable to the Industrial Group 5.4%

(11) Percentage of Standard Offer Expenses attributable to the Commercial Group 25.0%

(12) Percentage of Standard Offer Expenses attributable to the Residential Group 69.7%

(13) Working Capital Impact Allocated to Industrial Group $123,813

(14) Working Capital Impact Allocated to Commercial Group $573,209

(15) Working Capital Impact Allocated to Residential Group $1,598,107

(1)(a) per page 5, line (2) (1)(2)(d) Column (b) + Column (c)

(2)(a) per page 6 (1)(e) per page 5, line (1)

(1)(2)(b) Column (a) ÷ 365 (2)(e) Per Billing System Report

(1)(2)(c) per page 7, line (5) (1)(2)(f) Column (d) x Column (e)

(3) Line (1) Column (f) + Line (2) (f) (9) Line (6) + Line (7) + Line (8)

(4) pretax cost of capital per R.I.P.U.C. Docket No. 4323, Compliance Attachment 1, (10) Line (6) ÷ Line (9)

Schedule MDL-3-ELEC, page 61, Line 9, column (e) - Is based on 35% federal income tax rate (11) Line (7) ÷ Line (9)

(5) Line 3 x Line 4 (12) Line (8) ÷ Line (9)

(6) per Schedule ASC-2, page 5, column (a) (13) Line (5) x Line (10)






Estimated Calendar Year 2018

Customer Working

Days of Annual Payment Capital

Cost Percent Lag % CWC % Expense Requirement

(a) (b) (c) (d) (e) (f)

(1) 2017 Purchase Power Costs/Working Capital Requirement (21.853) -5.99% 12.82% 6.83% $289,018,509 $19,739,964

(2) Gross Receipts Tax 76.45 20.95% 12.82% 33.77% $11,686,003 $3,946,363

(3) Total $23,686,328

(4) Interest Rate 8.41%

(5) Working Capital Impact $1,992,020

(6) Standard Offer Service Revenue - Industrial Group $15,172,290

(7) Standard Offer Service Revenue - Commercial Group $70,652,820

(8) Standard Offer Service Revenue - Residential Group $197,208,886

(9) Standard Offer Service Revenue - Total $283,033,996

(10) Percentage of Standard Offer Expenses attributable to the Industrial Group 5.4%

(11) Percentage of Standard Offer Expenses attributable to the Commercial Group 25.0%

(12) Percentage of Standard Offer Expenses attributable to the Residential Group 69.7%

(13) Working Capital Impact Allocated to Industrial Group $107,569

(14) Working Capital Impact Allocated to Commercial Group $498,005

(15) Working Capital Impact Allocated to Residential Group $1,388,438

(1)(a) per page 5, line (2) (1)(2)(d) Column (b) + Column (c)

(2)(a) per page 6 (1)(e) per page 5, line (1)

(1)(2)(b) Column (a) ÷ 365 (2)(e) Per Billing System Report

(1)(2)(c) per page 7, line (5) (1)(2)(f) Column (d) x Column (e)

(3) Line (1) Column (f) + Line (2) (f) (9) Line (6) + Line (7) + Line (8)

(4) pretax cost of capital per R.I.P.U.C. Docket No. 4323, Compliance Attachment 1, (10) Line (6) ÷ Line (9)

Schedule MDL-3-ELEC, page 61, Line 9, column (e) - Is based on 21% federal income tax rate (11) Line (7) ÷ Line (9)

(5) Line 3 x Line 4 (12) Line (8) ÷ Line (9)






Calendar Year 2017

Purchased Power Accounts Payable Lag Calculation

End of

Invoice Invoice Service Elapsed % of Weighted

Month Expense Description Amount Period Invoice Date Due Date Payment Date (Days) Total Days

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

PURCHASED POWER INVOICES:

Feb 2017 Current Charge for September 2016 $109,654.54 9/30/2016 2/6/2017 2/20/2017 2/17/2017 140 0.04% 0.05

Feb 2017 Current Charge for January 2017 $5,665,996.17 1/31/2017 2/6/2017 2/20/2017 2/17/2017 17 1.96% 0.33



Feb 2017 Current Charge for September 2016 ($23,488.35) 9/30/2016 2/10/2017 2/21/2017 2/17/2017 140 -0.01% (0.01)








Mar 2017 Current Charge for October 2016 ($50,832.67) 10/31/2016 3/6/2017 3/20/2017 3/20/2017 140 -0.02% (0.02)

Mar 2017 Current Charge for February 2017 $4,958,715.34 2/28/2017 3/6/2017 3/20/2017 3/20/2017 20 1.72% 0.34

Mar 2017 Current Charge for October 2016 $9,140.47 10/31/2016 3/10/2017 3/20/2017 3/20/2017 140 0.00% 0.00






Mar 2017 Current Charge for October 2016 $8,394.58 10/31/2016 3/9/2017 3/20/2017 3/20/2017 140 0.00% 0.00



Apr 2017 Current Charge for November 2016 $4,963.07 11/30/2016 4/10/2017 4/20/2017 4/20/2017 141 0.00% 0.00

Apr 2017 Current Charge for March 2017 $4,486,311.95 3/31/2017 4/10/2017 4/20/2017 4/20/2017 20 1.55% 0.31










May 2017 Current Charge for April 2016 $3,589,955.26 4/30/2017 5/3/2017 5/22/2017 5/19/2017 19 1.24% 0.24

May 2017 Current Charge for December 2016 $193,685.01 12/31/2016 5/3/2017 5/22/2017 5/19/2017 139 0.07% 0.09



May 2017 Current Charge for April 2017 $4,370.04 4/30/2017 5/10/2017 5/22/2017 5/19/2017 19 0.00% 0.00

May 2017 Current Charge for December 2016 $1,763,271.46 12/31/2016 5/5/2017 5/22/2017 5/19/2017 139 0.61% 0.85


May 2017 Current Charge for December 2016 $2,084,238.20 12/31/2016 5/11/2017 5/22/2017 5/19/2017 139 0.72% 1.00






May 2017 Current Charge for May 2017 $1,712,147.23 4/30/2017 5/5/2017 6/20/2017 6/19/2017 50 0.59% 0.30

May 2017 Current Charge for January 2017 $126,706.01 12/31/2016 5/5/2017 6/20/2017 6/19/2017 170 0.04% 0.07

Jun 2017 Current Charge for January 2017 $115,471.36 1/31/2017 6/10/2017 6/20/2017 6/20/2017 140 0.04% 0.06

Jun 2017 Current Charge for May 2017 $3,295,359.60 5/31/2017 6/6/2017 6/20/2017 6/20/2017 20 1.14% 0.23




Jun 2017 Current Charge for May 2017 $652,641.49 5/31/2017 6/7/2017 6/20/2017 6/20/2017 20 0.23% 0.05

Jun 2017 Current Charge for Jan 2017 ($108,382.57) 1/31/2017 6/7/2017 6/20/2017 6/20/2017 140 -0.04% (0.05)



Jun 2017 Current Charge for May 2017 $725,977.40 5/31/2017 6/13/2017 6/20/2017 6/20/2017 20 0.25% 0.05

Jun 2017 Current Charge for Jan 2017 $22,732.44 1/31/2017 6/13/2017 6/20/2017 6/20/2017 140 0.01% 0.01


Jul 2017 Current Charge for June 2017 $5,898,633.09 6/30/2017 7/6/2017 7/20/2017 7/20/2017 20 2.04% 0.41

Jul 2017 Current Charge for February 2017 $135,015.85 2/28/2017 7/6/2017 7/20/2017 7/20/2017 142 0.05% 0.07




Jul 2017 Current Charge for February 2017 ($159,901.64) 2/28/2017 7/10/2017 7/20/2017 7/20/2017 142 -0.06% (0.08)









Aug 2017 Current Charge for March 2017 $181,798.58 3/31/2017 8/10/2017 8/20/2017 8/21/2017 143 0.06% 0.09


Aug 2017 Current Charge for July 2017 $6,922,348.00 7/31/2017 8/4/2017 8/21/2017 8/21/2017 21 2.40% 0.50



Aug 2017 Current Charge for March 2017 ($117,091.25) 3/31/2017 8/10/2017 8/21/2017 8/21/2017 143 -0.04% (0.06)



Calendar Year 2017


PURCHASED POWER INVOICES CONTINUED:



(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)


Aug 2017 Current Charge for July 2017 $746,971.34 7/31/2017 8/2/2017 8/31/2017 8/21/2017 21 0.26% 0.05



Aug 2017 Current Charge for March 2017 ($109,996.17) 3/31/2017 8/10/2017 8/21/2017 8/21/2017 143 -0.04% (0.05)





Sep 2017 Current Charge for August 2017 $6,462,061.63 8/31/2017 9/6/2017 9/20/2017 9/20/2017 20 2.24% 0.45

Sep 2017 Current Charge for April 2017 $52,947.61 4/30/2017 9/6/2017 9/20/2017 9/20/2017 143 0.02% 0.03




Sep 2017 Current Charge for April 2017 ($5,170.31) 4/30/2017 9/11/2017 9/20/2017 9/20/2017 143 0.00% (0.00)






Sep 2017 Current Charge for August 2017 $716,292.99 8/31/2017 9/10/2017 9/30/2017 9/20/2017 20 0.25% 0.05




Sep 2017 Current Charge for April 2017 ($4,657.04) 4/30/2017 9/19/2017 9/20/2017 9/20/2017 143 0.00% (0.00)

Oct 2017 Current Charge for September 2017 $1,062,837.06 9/30/2017 10/10/2017 10/20/2017 10/20/2017 20 0.37% 0.07

Oct 2017 Current Charge for May 2017 ($11,082.33) 5/31/2017 10/10/2017 10/20/2017 10/20/2017 142 0.00% (0.01)

Oct 2017 Current Charge for May 2017 $23,137.30 5/31/2017 10/4/2017 10/20/2017 10/20/2017 142 0.01% 0.01




Oct 2017 Current Charge for September 2017 $874,932.66 9/30/2017 10/5/2017 10/20/2017 10/20/2017 20 0.30% 0.06

Oct 2017 Current Charge for May 2017 ($46,860.61) 5/31/2017 10/5/2017 10/20/2017 10/20/2017 142 -0.02% (0.02)


Oct 2017 Current Charge for May 2017 $322.03 5/31/2017 10/10/2017 10/20/2017 10/20/2017 142 0.00% 0.00


Oct 2017 Current Charge for May 2017 ($12,325.94) 5/31/2017 10/10/2017 10/20/2017 10/20/2017 142 0.00% (0.01)

Oct 2017 Current Charge for September 2017 $711,323.62 9/30/2017 10/5/2017 10/31/2017 10/20/2017 20 0.25% 0.05



Oct 2017 Current Charge for May 2017 ($50,676.80) 5/31/2017 10/23/2017 10/23/2017 10/20/2017 142 -0.02% (0.02)


Nov 2017 Current Charge for June 2017 ($39,390.43) 6/30/2017 11/10/2017 11/20/2017 11/20/2017 143 -0.01% (0.02)

Nov 2017 Current Charge for October 2017 $2,947,765.08 10/31/2017 11/10/2017 11/20/2017 11/20/2017 20 1.02% 0.20

Nov 2017 Current Charge for June 2017 $87,501.62 6/30/2017 11/3/2017 11/20/2017 11/20/2017 143 0.03% 0.04



Nov 2017 Current Charge for October 2017 $30,739.96 6/30/2017 11/3/2017 11/20/2017 11/20/2017 143 0.01% 0.02

Nov 2017 Current Charge for October 2017 ($4,681.54) 6/30/2017 11/10/2017 11/20/2017 11/20/2017 143 0.00% (0.00)

Nov 2017 Current Charge for June 2017 ($4,800.00) 6/30/2017 11/10/2017 11/20/2017 11/20/2017 143 0.00% (0.00)





Nov 2017 Current Charge for June 2017 ($36,588.74) 6/30/2017 11/16/2017 11/20/2017 11/20/2017 143 -0.01% (0.02)

Dec 2017 Current Charge for July 2017 ($7,194.41) 7/31/2017 12/4/2017 12/27/2017 12/27/2017 149 0.00% (0.00)

Dec 2017 Current Charge for July 2017 $184,893.01 7/31/2017 12/5/2017 12/20/2017 12/20/2017 142 0.06% 0.09

Dec 2017 Current Charge for November 2017 $5,433,219.74 11/30/2017 12/5/2017 12/20/2017 12/20/2017 20 1.88% 0.38

Dec 2017 Current Charge for July 2017 ($35,762.05) 7/31/2017 12/14/2017 12/20/2017 12/20/2017 142 -0.01% (0.02)



Dec 2017 Current Charge for July 2017 $98,877.64 7/31/2017 12/8/2017 12/20/2017 12/20/2017 142 0.03% 0.05


Dec 2017 Current Charge for November 2017 $76,323.85 11/30/2017 11/3/2017 12/20/2017 12/20/2017 20 0.03% 0.01






Jan 2018 Current Charge for December 2017 $9,348,920.17 12/31/2017 1/4/2018 1/22/2018 1/22/2018 22 3.23% 0.71

Jan 2018 Current Charge for August 2017 $223,494.74 8/31/2017 1/4/2018 1/22/2018 1/22/2018 144 0.08% 0.11


Jan 2018 Current Charge for August 2017 ($29,834.32) 8/31/2017 1/9/2018 1/22/2018 1/22/2018 144 -0.01% (0.01)










Purchase to Date 263,341,496



Calendar Year 2017


SPOT MARKET PURCHASES:Jan-2017 Spot Market Purchase $2,165 1/13/2017 1/18/2017 1/20/2017 1/20/2017 7 0.00% 0.00

Jan-2017 Spot Market Purchase $72,981 1/19/2017 1/23/2017 1/25/2017 1/25/2017 6 0.03% 0.00


Jan-2017 Spot Market Purchase ($2,427) 1/26/2017 1/30/2017 2/3/2017 2/3/2017 8 0.00% (0.00)

Jan-2017 Spot Market Purchase ($13,798) 1/30/2017 2/1/2017 2/7/2017 2/7/2017 8 0.00% (0.00)



Jan-2017 Spot Market Purchase $1,383,186 2/8/2017 2/13/2017 2/15/2017 2/15/2017 7 0.48% 0.03

Feb-2017 Spot Market Purchase $18,745 2/13/2017 2/15/2017 2/17/2017 2/17/2017 4 0.01% 0.00




Feb-2017 Spot Market Purchase ($5,951) 2/27/2017 3/1/2017 3/7/2017 3/7/2017 8 0.00% (0.00)


Feb-2017 Spot Market Purchase ($3,050) 3/6/2017 3/8/2017 3/14/2017 3/14/2017 8 0.00% (0.00)

Feb-2017 Spot Market Purchase $1,166,864 3/8/2017 3/13/2017 3/15/2017 3/15/2017 7 0.40% 0.03

Mar-2017 Spot Market Purchase $4,132 3/13/2017 3/15/2017 3/17/2017 3/17/2017 4 0.00% 0.00

Mar-2017 Spot Market Purchase ($1,241) 3/16/2017 3/20/2017 3/24/2017 3/24/2017 8 0.00% (0.00)

Mar-2017 Spot Market Purchase ($58,437) 3/20/2017 3/22/2017 3/28/2017 3/28/2017 8 -0.02% (0.00)







Mar-2017 Spot Market Purchase $1,707,979 4/11/2017 4/18/2017 4/20/2017 4/20/2017 9 0.59% 0.05

Apr-2017 Spot Market Purchase ($7,824) 4/13/2017 4/19/2017 4/25/2017 4/25/2017 12 0.00% (0.00)


Apr-2017 Spot Market Purchase ($24,794) 4/24/2017 4/26/2017 5/2/2017 5/2/2017 8 -0.01% (0.00)





Apr-2017 Spot Market Purchase $949,843 5/10/2017 5/15/2017 5/17/2017 5/17/2017 7 0.33% 0.02

May-2017 Spot Market Purchase $23,918 5/15/2017 5/17/2017 5/19/2017 5/19/2017 4 0.01% 0.00

May-2017 Spot Market Purchase ($15,805) 5/18/2017 5/22/2017 5/26/2017 5/26/2017 8 -0.01% (0.00)

May-2017 Spot Market Purchase ($44,156) 5/22/2017 5/24/2017 5/31/2017 5/31/2017 9 -0.02% (0.00)


May-2017 Spot Market Purchase ($8,961) 5/26/2017 5/31/2017 6/6/2017 6/6/2017 11 0.00% (0.00)



May-2017 Spot Market Purchase $1,148,321 6/7/2017 6/12/2017 6/14/2017 6/14/2017 7 0.40% 0.03

Jun-2017 Spot Market Purchase ($7,741) 6/12/2017 6/14/2017 6/20/2017 6/20/2017 8 0.00% (0.00)

Jun-2017 Spot Market Purchase $60,838 6/15/2017 6/19/2017 6/21/2017 6/21/2017 6 0.02% 0.00

Jun-2017 Spot Market Purchase ($8,948) 6/19/2017 6/21/2017 6/27/2017 6/27/2017 8 0.00% (0.00)



Calendar Year 2017




(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

SPOT MARKET PURCHASES CONTINUED:Jun-2017 Spot Market Purchase ($14,428.98) 6/22/2017 6/26/2017 6/30/2017 6/30/2017 8 0.00% (0.00)

Jun-2017 Spot Market Purchase $12,215.41 6/26/2017 6/28/2017 6/30/2017 6/30/2017 4 0.00% 0.00





Jun-2017 Spot Market Purchase $2,261,164.56 7/12/2017 7/17/2017 7/19/2017 7/19/2017 7 0.78% 0.05

Jul-2017 Spot Market Purchase $61,363.27 7/17/2017 7/19/2017 7/21/2017 7/21/2017 4 0.02% 0.00







Aug-2017 Spot Market Purchase $1,938,851.96 8/9/2017 8/14/2017 8/16/2017 8/16/2017 7 0.67% 0.05

Aug-2017 Spot Market Purchase $97,519.02 8/14/2017 8/16/2017 8/18/2017 8/18/2017 4 0.03% 0.00





Aug-2017 Spot Market Purchase ($1,470.61) 8/31/2017 9/5/2017 9/11/2017 9/11/2017 11 0.00% (0.00)


Aug-2017 Spot Market Purchase $1,694,135.49 9/6/2017 9/11/2017 9/13/2017 9/13/2017 7 0.59% 0.04

Sep-2017 Spot Market Purchase $1,929.33 9/11/2017 9/13/2017 9/15/2017 9/15/2017 4 0.00% 0.00









Oct-2017 Spot Market Purchase $2,020,168.13 10/11/2017 10/16/2017 10/18/2017 10/18/2017 7 0.70% 0.05

Oct-2017 Spot Market Purchase ($28,497.67) 10/16/2017 10/18/2017 10/24/2017 10/24/2017 8 -0.01% (0.00)


Oct-2017 Spot Market Purchase ($6,211.80) 10/23/2017 10/25/2017 10/31/2017 10/31/2017 8 0.00% (0.00)



Oct-2017 Spot Market Purchase $22,780.73 11/2/2017 11/6/2017 11/8/2017 11/8/2017 6 0.01% 0.00


Oct-2017 Spot Market Purchase $1,944,503.95 11/7/2017 11/13/2017 11/15/2017 11/15/2017 8 0.67% 0.05

Nov-2017 Spot Market Purchase ($908.93) 11/13/2017 11/15/2017 11/21/2017 11/21/2017 8 0.00% (0.00)

Nov-2017 Spot Market Purchase ($18,341.75) 11/16/2017 11/20/2017 11/28/2017 11/28/2017 12 -0.01% (0.00)


Nov-2017 Spot Market Purchase ($9,328.18) 11/21/2017 11/27/2017 12/1/2017 12/1/2017 10 0.00% (0.00)



Nov-2017 Spot Market Purchase $7,857.26 12/4/2017 12/6/2017 12/8/2017 12/8/2017 4 0.00% 0.00

Nov-2017 Spot Market Purchase $2,372,221.51 12/6/2017 12/11/2017 12/13/2017 12/13/2017 7 0.82% 0.06

Dec-2017 Spot Market Purchase ($36,260.98) 12/11/2017 12/13/2017 12/19/2017 12/19/2017 8 -0.01% (0.00)


Dec-2017 Spot Market Purchase $117,727.96 12/18/2017 12/20/2017 12/22/2017 12/22/2017 4 0.04% 0.00







Dec-2017 Spot Market Purchase $5,640,647 1/10/2018 1/16/2018 1/18/2018 1/18/2018 8 1.95% 0.16

100.00%

(1) Total $289,018,509

(2) Weighted Average Lag Days from End of Service Period to Final Payment Date of Purchased Power Bill 21.853

(a) Month in which obligation for payment occurred

(b) Per invoices

(c) Per invoices

(d) Applicable service period

(e) Per invoices

(f) Per agreements

(g) Date paid

(h) Number of days between Column (d) and Column (g)

(i) Column (c) ÷ Line (1)

(j) Column (h) x Column (i)

(1) Sum of Column (c)

(2) Sum of Column (j)


WeightedGross Average

Earnings Tax Days From Percent Payment Days fromPayment Date (1) Service Period Payment (1) Amount Year End

(a) (b) (c) (d) (e)

3/15/2017 (74) 45.96% $18,008,000.00 (34.01)6/9/2017 (160) 54.04% $21,173,537.00 (86.46)

9/15/2017 (258) 0.00% $0.00 0.0012/15/2017 (349) 0.00% $0.00 0.00

100.00% $39,181,537.00 (120.47)

AverageService Days from Days fromPeriod Year end Year end

(f) (g) (h)

1/31/2017 (31)2/28/2017 (59)3/31/2017 (90)4/30/2017 (120)5/31/2017 (151)6/30/2017 (181)7/31/2017 (212)8/31/2017 (243)9/30/2017 (273)

10/31/2017 (304)11/30/2017 (334)12/31/2017 (365)

Average End of Service Period Date (2,363) /12 = (196.92)

Weighted Average Payment Days from Year End (120.47)Average Days from End of Service 196.92 Period for Payment of Gross Earnings Tax 76.45

(1) Rhode Island law (Sec. 44-26) requires the payment of estimated CorporateGross Earnings Tax (GET) during the tax year. This code section also stipulates theabove payment dates and minimum payment percentages. Code Sec. 44-1extends the required payment dates that fall upon a Saturday, Sunday orlegal holiday, to the next business day. Finally, payments are consideredtimely under Sec. 44-1 with evidence of mailing on or before the required date.The Company pays 40% of its prior year GET on March 15 and 60% ofits prior year GET on June 15. Any remaining tax due for the calendar year is paid with its GET return on February 28 of the subsequent year.

Narragansett Electric CompanyCalendar Year 2017Gross Earnings Tax



Calendar Year 2017

Customer Days of

Accts. Receivable Days Sales in

Service Period Ending Balance Sales In Month Accts Receivable

(a) (b) (c) (d)

1/31/2017 $115,926,142 $81,215,189 31 44.25

2/28/2017 $118,469,667 $78,624,741 28 42.19

3/31/2017 $130,734,495 $74,687,348 31 54.26

4/30/2017 $107,747,234 $71,649,033 30 45.11

5/31/2017 $98,392,550 $61,040,069 31 49.97

6/30/2017 $116,803,546 $70,342,014 30 49.82

7/31/2017 $113,833,141 $87,952,679 31 40.12

8/31/2017 $112,097,321 $90,591,204 31 38.36

9/30/2017 $125,259,342 $81,086,543 30 46.34

10/31/2017 $103,069,693 $74,604,634 31 42.83

11/30/2017 $106,602,086 $77,897,785 30 41.05

12/31/2017 $127,939,223 $79,566,919 31 49.85

(1) Total Days 544.15

(2) Average Lag 45.35

(3) Average Lag from date meter is read 1.46

(4) Total Average Days Lag 46.81

(5) Customer Payment Lag-annual percent 12.82%

(a) Accounts Receivable per general ledger at end of applicable month

(b) per Company revenue reports

(c) Number of days in applicable service period

(d) Column (a) ÷ Column (b) x Column (c)

(1) Total of Column (d)

(2) Line (1) ÷ 12

(3) per meter reading lag study

(4) Line (2) + Line (3)

(5) Line (4) ÷ 365


Schedule ASC

-7




Schedule ASC-7

Calculation of SOS Administrative Cost Reconciliation Adjustment Factors

Standard Offer Service Administrative Cost ReconciliationCalculation of SOS Administrative Cost Reconciliation Adjustment Factor

Industrial Group SOS Administrative Cost Reconciliation Adjustment Factor

(1) Industrial Group Under Recovery for the period January 1, 2017 through December 31, 2017 $71,824


(3) Total Industrial Group SOS Admin. Cost Under Recovery $73,031

(4) forecasted Industrial Group SOS kWh for the period April 1, 2018 through March 31, 2019 249,842,034

(5) Industrial Group SOS Administrative Cost Reconciliation Adjustment Factor $0.00029

Commercial Group SOS Administrative Cost Reconciliation Adjustment Factor

(6) Commercial Over Recovery for the period January 1, 2017 through December 31, 2017 ($37,235)

(7) Interest During Refund Period ($626)

(8) Total Commercial Group SOS Admin. Cost Over Recovery ($37,861)

(9) forecasted Commercial Group SOS kWh for the period April 1, 2018 through March 31, 2019 957,409,005

(10) Commercial Group SOS Administrative Cost Reconciliation Adjustment Factor ($0.00003)

Residential Group SOS Administrative Cost Reconciliation Adjustment Factor

(11) Residential Group Over Recovery for the period January 1, 2017 through December 31, 2017 ($229,655)

(12) Interest During Refund Period ($3,861)

(13) Total Residential Group SOS Admin. Cost Over Recovery ($233,516)

(14) forecasted Residential Group SOS kWh for the period April 1, 2018 through March 31, 2019 2,618,774,950

(15) Residential Group SOS Administrative Cost Reconciliation Adjustment Factor ($0.00008)

(1) (9) per Schedule ASC-3, Page 2, Line (4)(2) per Page 2 (10) Line (8) ÷ Line (9), truncated to five decimal places(3) Line (1) + Line (2) (11)(4) per Schedule ASC-3, Page 2, Line (4) (12) per Page 2(5) Line (3) ÷ Line (4), truncated to five decimal places (13) Line (11) + Line (12)(6) (14) per Schedule ASC-3, Page 2, Line (4)(7) per Page 2 (15) Line (13) ÷ Line (14), truncated to five decimal places(8) Line (6) + Line (7)

per Schedule ASC-5, Page 4, Line (3)




Res

iden

tial

Com

mer

cial

Indu

stri

al

Beg

inni

ngE

ndin

gIn

tere

stB

egin

ning

End

ing

Inte

rest

Beg

inni

ngE

ndin

gIn

tere

stM

onth

Bal

ance

Ref

und

Bal

ance

Rat

eIn

tere

stM

onth

Bal

ance

Ref

und

Bal

ance

Rat

eIn

tere

stM

onth

Bal

ance

Rec

over

yB

alan

ceR

ate

Inte

rest

(1)

(2)

(3)

(4)

(5)

(1)

(2)

(3)

(4)

(5)

(1)

(2)

(3)

(4)

(5)

Jan-

18$2

29,6

55$2

29,6

551.

84%

$352

Jan-

18$3

7,23

5$3

7,23

51.

84%

$57

Jan-

18($

71,8

24)

($71

,824

)1.

84%

($11

0)F

eb-1

8$2

30,0

07$2

30,0

071.

84%

$353

Feb

-18

$37,

292

$37,

292

1.84

%$5

7F

eb-1

8($

71,9

34)

($71

,934

)1.

84%

($11

0)M

ar-1

8$2

30,3

60$2

30,3

602.

33%

$447

Mar

-18

$37,

349

$37,

349

2.33

%$7

3M

ar-1

8($

72,0

44)

($72

,044

)2.

33%

($14

0)A

pr-1

8$2

30,8

07$1

9,23

4$2

11,5

732.

33%

$429

Apr

-18

$37,

422

$3,1

18$3

4,30

32.

33%

$70

Apr

-18

($72

,184

)($

6,01

5)($

66,1

69)

2.33

%($

134)

May

-18

$212

,003

$19,

273

$192

,730

2.33

%$3

93M

ay-1

8$3

4,37

3$3

,125

$31,

248

2.33

%$6

4M

ay-1

8($

66,3

03)

($6,

028)

($60

,275

)2.

33%

($12

3)

Jun-

18$1

93,1

23$1

9,31

2$1

73,8

102.

33%

$356

Jun-

18$3

1,31

2$3

,131

$28,

180

2.33

%$5

8Ju

n-18

($60

,398

)($

6,04

0)($

54,3

58)

2.33

%($

111)

Jul-

18$1

74,1

67$1

9,35

2$1

54,8

152.

33%

$319

Jul-

18$2

8,23

8$3

,138

$25,

101

2.33

%$5

2Ju

l-18

($54

,470

)($

6,05

2)($

48,4

18)

2.33

%($

100)

Aug

-18

$155

,134

$19,

392

$135

,742

2.33

%$2

82A

ug-1

8$2

5,15

2$3

,144

$22,

008

2.33

%$4

6A

ug-1

8($

48,5

18)

($6,

065)

($42

,453

)2.

33%

($88

)

Sep

-18

$136

,025

$19,

432

$116

,593

2.33

%$2

45S

ep-1

8$2

2,05

4$3

,151

$18,

904

2.33

%$4

0S

ep-1

8($

42,5

41)

($6,

077)

($36

,464

)2.

33%

($77

)

Oct

-18

$116

,838

$19,

473

$97,

365

2.33

%$2

08O

ct-1

8$1

8,94

3$3

,157

$15,

786

2.33

%$3

4O

ct-1

8($

36,5

41)

($6,

090)

($30

,450

)2.

33%

($65

)

Nov

-18

$97,

573

$19,

515

$78,

058

2.33

%$1

71N

ov-1

8$1

5,82

0$3

,164

$12,

656

2.33

%$2

8N

ov-1

8($

30,5

16)

($6,

103)

($24

,412

)2.

33%

($53

)

Dec

-18

$78,

229

$19,

557

$58,

672

2.33

%$1

33D

ec-1

8$1

2,68

4$3

,171

$9,5

132.

33%

$22

Dec

-18

($24

,466

)($

6,11

6)($

18,3

49)

2.33

%($

42)

Jan-

19$5

8,80

5$1

9,60

2$3

9,20

32.

33%

$95

Jan-

19$9

,534

$3,1

78$6

,356

2.33

%$1

5Ja

n-19

($18

,391

)($

6,13

0)($

12,2

61)

2.33

%($

30)

Feb

-19

$39,

298

$19,

649

$19,

649

2.33

%$5

7F

eb-1

9$6

,372

$3,1

86$3

,186

2.33

%$9

Feb

-19

($12

,290

)($

6,14

5)($

6,14

5)2.

33%

($18

)

Mar

-19

$19,

706

$19,

706

$02.

33%

$19

Mar

-19

$3,1

95$3

,195

$02.

33%

$3M

ar-1

9($

6,16

3)($

6,16

3)$0

2.33

%($

6)

$3,8

61$6

26($

1,20

7)

(1)

Jan-

18 p

er S

ched

ule

AS

C-5

, Pag

e 2,

3, 4

, Lin

e (3

)(2

)F

or A

pr-2

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(C

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)) ÷

12.

For

May

-201

8, (

Col

umn

(1))

÷ 1

1, e

tc.

(3)

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umn

(1)

- C

olum

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)(4

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ate

for

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epos

its

(5)

{[C

olum

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) +

Col

umn

(3)]

÷ 2

} x

[Col

umn

(4)

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]

Cal

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ecem

ber

31, 2

017


Schedule A

SC-8




Schedule ASC-8

Unbilled SOS Billing Adjustment

MonthNet Unbilled Adjustments

ResidentialNet Unbilled Adjustments

CommercialTotal Net Unbilled

Adjustments

(a) (b) (c)

Jan-17 ($19,602) ($2,939) ($22,541)

Feb-17 $1,234 $2,743 $3,977

Mar-17 $7,866 $1,674 $9,540

Apr-17 ($4,584) ($192) ($4,776)

May-17 ($11,216) ($2,789) ($14,004)

Jun-17 ($14,496) ($2,164) ($16,660)

Jul-17 ($7,776) ($585) ($8,361)

Aug-17 ($4,269) ($620) ($4,889)

Sep-17 ($685) $1,187 $502

Oct-17 ($8,869) ($2,958) ($11,827)

Nov-17 ($30,603) ($8,570) ($39,173)

Dec-17 ($23,429) ($6,013) ($29,442)

Totals ($116,429) ($21,225) ($137,654)

(a) - (b) From Company reports - (negative values are credits which previously appeared on customer bills)

(c) Sum of (a) through (b)

Unbilled Billing Adjustment Revenue

Unbilled Standard Offer Service Billing Adjustments


Schedule A

SC-9




Schedule ASC-9

Calculation of Proposed Non-Bypassable Transition Charge

Calculation of Proposed Non-bypassable Transition Charge for April 1, 2018

Calculation of 2018 Non-Bypassable Transition Charge

(1) Base Transition Credit per kWh ($0.00083)

(2) Transition Charge Adjustment Factor per kWh ($0.00004)

(3) Proposed Total Transition Credit for April 1, 2018 ($0.00087)

(1) per page 1, Line (6), converted to dollars

(2) per Schedule ASC-10, page 3, line (3)

(3) Line (1) + Line (2)


Calculation of Proposed Non-bypassable Transition Charge for April 1, 2018

Section 1: Individual CTC Amounts

CTC Forecasted Expected

Charge GWhs CTC Costs

(1) (2) (3)

Narragansett

2018 ($0.00060) 6,463.337 ($3,878,002)

BVE

2018 ($0.00150) 1,713.946 ($2,570,919)

Newport

2018 ($0.00140) 667.717 ($934,804)

Total CTC Costs ($7,383,725)

Section 2: Total Estimated CTC Costs and Transition Charge Calculation

Total Total

Company Company

Total GWhs CTC Costs

(4) (5)

2018 8,845.000 ($7,383,725)

(6) Transition Charge ($ per kWh) ($0.00083)

(1)

(2)

(3) (1) x (2) x 1,000,000

(4) Sum of Narragansett, BVE and Newport GWhs for 2018

(5) Sum of Narragansett, BVE and Newport CTC Costs for 2018

(6) (5) ÷ (4), truncated to 5 decimal places

BVE - January 2018 BE/NWPT Combined CTC Reconciliation Report, Schedule 1 BVE page 1, column 2Newport - January 2018 BE/NWPT Combined,CTC Reconciliation Report, Schedule 1,NWPT page 1, column 2

Narragansett - January 2018 NEP CTC Reconciliation Report, Schedule 1, page 1, line 45 column 10BVE - January 2018 BVE/NWPT Combined CTC Reconciliation Report, Schedule 1 BVE, page 1, column 8Newport - January 2018 BVE/NWPT Combined CTC Reconciliation Report, Schedule 1 NWPT , page 1, column 8

Narragansett - January 2018 NEP CTC Reconciliation Report, Schedule 1, page 1, line 45, column 4


Schedule ASC

-10




Schedule ASC-10

Non-Bypassable Transition Charge Reconciliation and

Non-Bypassable Transition Adjustment Charge Reconciliation

For the period January 2017 through December 2017

For the Period January 2017 through December 2017

(Under)/Over Transition Contract (Under)/Over (Under)/OverBeginning Charge Termination Monthly Ending Interest Interest Monthly Ending

Month Balance Revenue Expense (Under)/Over Balance Balance Rate Interest Adjustments Balance(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

Jan-17 $0 $293,147 $84,720 $208,427 $208,427 $104,214 2.14% $186 $208,613

Feb-17 $208,613 $73,647 $59,549 $14,098 $222,711 $215,662 2.14% $385 $223,096

Mar-17 $223,096 $70,391 $69,219 $1,172 $224,268 $223,682 1.84% $343 $224,611

Apr-17 $224,611 $66,758 $62,067 $4,691 $229,302 $226,957 1.84% $348 $159,178 $388,828

May-17 $388,828 $53,398 $53,896 ($498) $388,330 $388,579 1.84% $596 $388,926

Jun-17 $388,926 $59,422 $72,712 ($13,290) $375,637 $382,282 1.84% $586 $376,223

Jul-17 $376,223 $69,922 $83,255 ($13,334) $362,889 $369,556 1.84% $567 $363,456

Aug-17 $363,456 $71,037 $78,980 ($7,942) $355,513 $359,485 1.84% $551 $356,065

Sep-17 $356,065 $64,963 $66,229 ($1,265) $354,799 $355,432 1.84% $545 $355,344

Oct-17 $355,344 $59,428 $62,821 ($3,393) $351,952 $353,648 1.84% $542 $352,494

Nov-17 $352,494 $57,968 $63,094 ($5,126) $347,368 $349,931 1.84% $537 $347,904

Dec-17 $347,904 $58,344 $64,107 ($5,764) $342,140 $345,022 1.84% $529 $342,669

Jan-18 $342,669 $10,032 $10,032 $352,701 $347,685 1.84% $533 $353,234

Total $0 1,008,456 $820,647 $187,809 $187,809 $6,247 $159,178 $353,234

Column (a) prior month column (j) Column (b) per Company reports

Includes an adjustment of $225,897 to increase revenue plus interest associated with an account which was under-billed due to incorrect meter programmingColumn (c) monthly CTC bills from New England Power CompanyColumn (d) Column (b) - Column (c)Column (e) Column (a) + Column (d)Column (f) [Column (a) + Column (e)] ÷ 2Column (g) Customer Deposit RateColumn (h) [Column (f) x (Column (g)] ÷12Column (i)Column (j) Column (e) + Column (h) + Column (i)

Ending Balance from prior period reconciliation per Page 2

Transition Service Reconciliation

Base Reconciliation


Transition Service ReconciliationFor the Period January 2017 through December 2017

Status of Prior Period Over/(Under) Collection

Section 1

Incurred: January 1, 2015 through December 31, 2015Recovery Period: April 1, 2016 through March 31, 2017

Beginning EndingOver/(Under) Over/(Under) Ending

Recovery Transition Charge Recovery Interest Interest Monthly BalanceMonth Balance (Credit)/Charge Balance Balance Rate Interest w/ Interest

(a) (b) (c) (d) (e) (f) (g)

Jan-16 $5,216,525 $0 $5,216,525 $5,216,525 0.00% $0 $5,216,525Feb-16 $5,216,525 $0 $5,216,525 $5,216,525 2.54% $11,042 $5,227,567Mar-16 $5,227,567 $0 $5,227,567 $5,227,567 2.14% $9,322 $5,236,889

(1) Apr-16 $5,236,889 ($171,649) $5,065,241 $5,151,065 2.14% $9,186 $5,074,427May-16 $5,074,427 ($348,130) $4,726,296 $4,900,361 2.14% $8,739 $4,735,035Jun-16 $4,735,035 ($421,359) $4,313,676 $4,524,356 2.14% $8,068 $4,321,744Jul-16 $4,321,744 ($477,342) $3,844,402 $4,083,073 2.14% $7,281 $3,851,684

Aug-16 $3,851,684 ($542,490) $3,309,194 $3,580,439 2.14% $6,385 $3,315,579Sep-16 $3,315,579 ($512,615) $2,802,964 $3,059,272 2.14% $5,456 $2,808,420Oct-16 $2,808,420 ($403,060) $2,405,360 $2,606,890 2.14% $4,649 $2,410,009

Nov-16 $2,410,009 ($371,952) $2,038,058 $2,224,033 2.14% $3,966 $2,042,024Dec-16 $2,042,024 ($402,580) $1,639,444 $1,840,734 2.14% $3,283 $1,642,726Jan-17 $1,642,726 ($441,144) $1,201,583 $1,422,154 2.14% $2,536 $1,204,119Feb-17 $1,204,119 ($413,846) $790,273 $997,196 2.14% $1,778 $792,051Mar-17 $792,051 ($403,428) $388,623 $590,337 1.84% $905 $389,528

(2) Apr-17 $389,528 ($230,770) $158,758 $274,143 1.84% $420 $159,178

Note: Beginning Balance from Schedule ASC-10, page 1, Docket No. 4599, Feb. 2016; January 2016 interest was included in ending balance

Section 2


Beginning EndingOver/(Under) Over/(Under) Ending

Recovery Transition Charge Recovery Interest Interest Monthly BalanceMonth Balance (Credit)/Charge Balance Balance Rate Interest w/ Interest

(a) (b) (c) (d) (e) (f) (g)

Jan-17 ($3,563,700) $0 ($3,563,700) ($3,563,700) 0.00% $0 ($3,563,700)Feb-17 ($3,563,700) $0 ($3,563,700) ($3,563,700) 2.14% ($6,355) ($3,570,055)Mar-17 ($3,570,055) $0 ($3,570,055) ($3,570,055) 1.84% ($5,474) ($3,575,529)

(1) Apr-17 ($3,575,529) $100,124 ($3,475,405) ($3,525,467) 1.84% ($5,406) ($3,480,811)May-17 ($3,480,811) $249,037 ($3,231,774) ($3,356,292) 1.84% ($5,146) ($3,236,920)Jun-17 ($3,236,920) $273,775 ($2,963,145) ($3,100,032) 1.84% ($4,753) ($2,967,898)Jul-17 ($2,967,898) $336,349 ($2,631,549) ($2,799,724) 1.84% ($4,293) ($2,635,842)

Aug-17 ($2,635,842) $340,567 ($2,295,276) ($2,465,559) 1.84% ($3,781) ($2,299,056)Sep-17 ($2,299,056) $308,547 ($1,990,509) ($2,144,783) 1.84% ($3,289) ($1,993,798)Oct-17 ($1,993,798) $279,856 ($1,713,942) ($1,853,870) 1.84% ($2,843) ($1,716,784)

Nov-17 ($1,716,784) $271,646 ($1,445,139) ($1,580,962) 1.84% ($2,424) ($1,447,563)Dec-17 ($1,447,563) $272,672 ($1,174,891) ($1,311,227) 1.84% ($2,011) ($1,176,902)Jan-18 ($1,176,902) $330,844 ($846,058) ($1,011,480) 1.84% ($1,551) ($847,609)Feb-18 ($847,609) $0 ($847,609) ($847,609) 1.84% ($1,300) ($848,908)Mar-18 ($848,908) $0 ($848,908) ($848,908) 2.33% ($1,648) ($850,557)

(2) Apr-18 ($850,557) $0 ($850,557) ($850,557) 2.33% ($1,652) ($852,208)

Note: Beginning Balance from Schedule ASC-10, page 1, Docket No. 4691, Feb 2017; January 2017 interest was included in ending balance

(1) represents revenue associated with consumption after April 1(2) represents revenue associated with consumption prior to April 1

(a) prior month column (g) (e) Customer Deposits Rate(b) monthly revenue reports (f) [Column (d) x (Column (e)] ÷ 12(c) Column (a) + Column (b) (g) Column (c) + Column (f)(d) (Column (a) + Column (c)) ÷ 2


Transition Service ReconciliationFor the Period January 2017 through December 2017

Beginning Ending Interest

Month Balance Refund/(Charge) Balance Rate Interest

(a) (b) (c) (d) (e)

Jan-18 $353,234 $353,234 1.84% $542

Feb-18 $353,776 $353,776 1.84% $542

Mar-18 $354,318 $354,318 2.33% $688

Apr-18 $355,006 $29,584 $325,422 2.33% $661

May-18 $326,083 $29,644 $296,439 2.33% $604

Jun-18 $297,043 $29,704 $267,339 2.33% $548

Jul-18 $267,887 $29,765 $238,122 2.33% $491

Aug-18 $238,613 $29,827 $208,786 2.33% $434

Sep-18 $209,221 $29,889 $179,332 2.33% $377

Oct-18 $179,709 $29,952 $149,758 2.33% $320

Nov-18 $150,078 $30,016 $120,062 2.33% $262

Dec-18 $120,324 $30,081 $90,243 2.33% $204

Jan-19 $90,448 $30,149 $60,298 2.33% $146

Feb-19 $60,445 $30,222 $30,222 2.33% $88

Mar-19 $30,310 $30,310 $0 2.33% $29

$5,938

(1) Total Transition Over Collection plus Interest during Refund Period $359,172

(2) forecasted kWh deliveries for the period April 1, 2018 through March 31, 2019 7,292,662,088

(3) Transition Adjustment Credit Factor per kWh ($0.00004)

(a) Column (e) from previous month; beginning balance from page 1

(b) For Apr, (Column (a)) ÷ 12. For May, (Column (a)) ÷ 11, etc.

(c) Column (a) - Column (b)

(d) Current Rate for Customer Deposits

(e) {([Column (a) + Column (c)] ÷ 2) x Column (d)} ÷ 12

(1) beginning balance in Column (a) + total interest in Column (e)

(2) per Company forecast

(3) [Line (1) ÷ Line (2)] x -1, truncated to 5 decimal places

Calculation of Interest During the Refund/Recovery Period


Schedule A

SC-11




Schedule ASC-11

Calculation of Proposed Base Transmission Charges

Calculation of 2018 Base Transmission FactorsEffective April 1, 2018 through March 31, 2019

Total A16/ A60 C06 G02 B32/G32 B62/G62/X01 S05/S06/S10/S14

( 1) Estimated Transmission Expenses $208,083,113

( 2) Coincident Peak Allocator 100.00% 44.75% 9.11% 17.30% 23.48% 5.04% 0.32%

( 3) Estimated 2018 Transmission Expenses by Rate Class $208,083,113 $93,122,194 $18,955,935 $35,998,449 $48,854,699 $10,477,300 $674,536

( 4) Allocated Estimated 2017 Transmission Expenses $212,722,033 $95,975,112 $18,976,592 $36,301,176 $49,857,577 $10,734,534 $877,043

( 5) Increase/(Decrease) ($4,638,920) ($2,852,918) ($20,656) ($302,727) ($1,002,878) ($257,234) ($202,506)

( 6) Percentage Increase/(Decrease) -2.18% -2.97% -0.11% -0.83% -2.01% -2.40% -23.09%

( 7) Forecast 2018 Demand kW 11,305,379 4,601,549 5,576,910 1,126,919

( 8) Forecast kWh for the period April 1, 2018 through March 31, 2019 7,292,662,088 2,952,217,339 598,406,291 1,290,644,353 1,958,411,647 446,170,232 46,812,226

( 9) Current Transmission kW Charge $4.37 $4.69 $3.40

(10) Proposed Transmission kW Charge $4.37 $4.69 $3.40

(11) Transmission Expenses to be Recovered on a kW Basis $50,096,004 $20,108,771 $26,155,707 $3,831,525

(12) Transmission Expenses to be Recovered on a kWh Basis $157,987,109 $93,122,194 $18,955,935 $15,889,677 $22,698,992 $6,645,775 $674,536

(13) Proposed Transmission kWh Charge $0.03154 $0.03167 $0.01231 $0.01159 $0.01489 $0.01440

( 1) per Schedule PVD-1, Page 1, Line (11)( 2) per Page 2, Column (j)( 3) Line 2 x Total Line 1( 4)

( 5) Line 3 - Line 4( 6) Line 5 ÷ Line 4( 7) per Company forecast( 8) per Company forecast( 9) per current tariffs

(10) Higher of current charge or Line 9 x (1 - Line 6)(11) Line 7 x Line 10(12) Line 3 - Line 11

(13) Line 12 ÷ Line 8 truncated to five decimal places

Schedule ASC-11, Page 1 of 2, Line (3), Docket No. 4691


Wei

ght=

67.5

%W

eigh

t=32

.5%

12 M

onth

s End

ed 1

2/31

/200

812

Mon

ths E

nded

11/

30/2

011

Est

imat

ed -

12 M

onth

s 03/

31/2

019

Lin

eR

ate

Cla

ssM

Wh

Cla

ss 1

2CP

Loa

d Fa

ctor

at

12C

PM

Wh

Cla

ss 1

2CP

Loa

d Fa

ctor

at

12C

P

Ave

rage

Loa

d Fa

ctor

at

12C

P

Fore

cast

ed

MW

hC

lass

12C

PE

stim

ated

- 12

M

onth

s 03

/31/

2019

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)(j

)1

A16

-A60

3,01

6,60

055

4,46

362

.1%

3,12

6,23

956

7,92

762

.8%

62.3

%2,

952,

217

540,

560

44.8

%2

C-0

654

4,43

910

1,46

661

.3%

565,

451

101,

174

63.8

%62

.1%

598,

406

110,

036

9.1%

3G

021,

384,

485

225,

130

70.2

%1,

332,

785

213,

873

71.1

%70

.5%

1,29

0,64

420

8,96

617

.3%

4B

32-G

322,

106,

494

306,

559

78.4

%2,

062,

549

295,

627

79.6

%78

.8%

1,95

8,41

228

3,59

423

.5%

5B

62-G

62-X

-01

581,

455

77,9

2385

.2%

545,

160

77,0

5980

.8%

83.7

%44

6,17

060

,819

5.0%

6S0

5-S0

6-S1

0-S1

470

,565

5,59

014

4.1%

69,8

606,

611

120.

6%13

6.5%

46,8

123,

916

0.32

%7 8

Syst

em7,

704,

038

1,27

1,13

169

.2%

7,70

2,04

41,

262,

270

69.7

%7,

292,

662

1,20

7,89

110

0.0%

(a)

per

Com

pany

rec

ords

(d)

per

Com

pany

rec

ords

(g)

colu

mn

(c)

x 67

.5%

+ c

olum

n (f

) x

32.5

%

(j)

colu

mn

(i)

÷ co

lum

n (i

) T

otal

(b)

2008

ave

rage

mon

thly

CP

(e)

2011

ave

rage

mon

thly

CP

(h)

from

Com

pany

for

ecas

t(c

)co

lum

n (a

) ÷

[col

umn

(b)

x 8,

760

hour

s](f

)co

lum

n (d

) ÷

[col

umn

(e)

x 8,

760

hour

s](i

)co

lum

n (h

) ÷

colu

mn

(g)

÷ 8,

760

hour

s


Schedule ASC

-12




Schedule ASC-12

Transmission Service Reconciliation For the period January 2017 through December 2017


Beginning Transmission Transmission Monthly Ending


(a) (b) (c) (d) (e)

(1) Jan-17 ($5,430,184) $6,953,513 $15,199,636 ($8,246,123) ($13,676,308)

Feb-17 ($13,676,308) $14,095,150 $13,812,551 $282,599 ($13,393,709)

Mar-17 ($13,393,709) $13,722,476 $14,547,548 ($825,072) ($14,218,781)

Apr-17 ($14,218,781) $14,760,067 $12,960,885 $1,799,181 ($12,419,600)

May-17 ($12,419,600) $14,958,349 $17,130,512 ($2,172,163) ($14,591,762)

Jun-17 ($14,591,762) $16,824,018 $20,489,900 ($3,665,883) ($18,257,645)

Jul-17 ($18,257,645) $20,146,269 $18,260,968 $1,885,301 ($16,372,344)

Aug-17 ($16,372,344) $20,369,689 $17,070,271 $3,299,418 ($13,072,926)

Sep-17 ($13,072,926) $18,341,281 $17,090,118 $1,251,162 ($11,821,763)

Oct-17 ($11,821,763) $16,624,577 $13,473,591 $3,150,986 ($8,670,778)

Nov-17 ($8,670,778) $16,261,165 $14,870,938 $1,390,228 ($7,280,550)

Dec-17 ($7,280,550) $16,294,359 $16,087,495 $206,864 ($7,073,686)

(2) Jan-18 ($7,073,686) $11,359,403 $0 $11,359,403 $4,285,717

Total ($5,430,184) $200,710,316 $190,994,415 $9,715,901 $4,285,717

Adjustments:

(3) Ending Balance Over/(Under) Incurred During 2015 ($442,704)

Total Pre-Interest Adjustments: ($442,704)

Ending Balance Prior to Application of Interest $3,843,013

(4) Interest $9,189

Base Transmission Reconciliation Balance with Interest $3,852,203

(1) Reflects kWhs consumed after January 1

(2) Reflects kWhs consumed prior to January 1

(3) Sum of Over/(Under) Ending Balances on Page 2

(4) [(Beginning Balance + Ending Balance ) ÷ 2] x [(2.14% x 2/12) + (1.84% x 10/12)]

Interest not calculated on ISO-NE Disgorgement Credit

(a) Jan.-17, True-Up of 2016 Expenses + Reversal of double refund of ISO-NE Disgorgement Credit

Feb.-17 through Jan.-18, Column (e) from previous row

(b) Page 3

(c) Page 4



Transmission Service ReconciliationFor the Period January 2017 through December 2017

Base Reconciliation - All Classes


Ove

r/(U

nder

)O

ver/

(Und

er)

Ove

r/(U

nder

)

Beg

inni

ngM

onth

lyE

ndin

gB

egin

ning

Mon

thly

End

ing

Beg

inni

ngM

onth

lyE

ndin

g

Mon

thB

alan

ceR

even

ueE

xpen

seO

ver/

(Und

er)

Bal

ance

Bal

ance

Rev

enue

Exp

ense

Ove

r/(U

nder

)B

alan

ceB

alan

ceR

even

ueE

xpen

seO

ver/

(Und

er)

Bal

ance

(a)

(b)

(c)

(d)

(e)

(a)

(b)

(c)

(d)

(e)

(a)

(b)

(c)

(d)

(e)

Jan-

17($

2,58

1,48

7)$2

,942

,446

$7,2

33,7

20($

4,29

1,27

4)($

6,87

2,76

2)($

404,

201)

$563

,843

$1,0

73,6

51($

509,

808)

($91

4,00

9)($

863,

206)

$1,0

24,7

48$2

,369

,917

($1,

345,

169)

($2,

208,

374)

Feb

-17

($6,

872,

762)

$6,5

39,1

40$6

,754

,422

($21

5,28

2)($

7,08

8,04

4)($

914,

009)

$1,3

22,8

30$9

08,8

44$4

13,9

86($

500,

023)

($2,

208,

374)

$2,3

61,5

80$2

,179

,722

$181

,859

($2,

026,

516)

Mar

-17

($7,

088,

044)

$6,0

78,3

21$6

,968

,717

($89

0,39

6)($

7,97

8,43

9)($

500,

023)

$1,2

86,4

41$9

39,5

58$3

46,8

83($

153,

139)

($2,

026,

516)

$2,4

18,7

54$2

,262

,787

$155

,966

($1,

870,

550)

Apr

-17

($7,

978,

439)

$6,4

68,9

03$5

,782

,969

$685

,934

($7,

292,

505)

($15

3,13

9)$1

,389

,340

$821

,449

$567

,891

$414

,752

($1,

870,

550)

$2,5

95,1

07$2

,156

,406

$438

,700

($1,

431,

849)

May

-17

($7,

292,

505)

$6,2

35,0

02$7

,925

,015

($1,

690,

014)

($8,

982,

519)

$414

,752

$1,3

56,8

06$1

,407

,205

($50

,399

)$3

64,3

52($

1,43

1,84

9)$2

,805

,063

$2,8

63,2

44($

58,1

81)

($1,

490,

031)

Jun-

17($

8,98

2,51

9)$7

,116

,919

$9,0

76,9

73($

1,96

0,05

4)($

10,9

42,5

72)

$364

,352

$1,4

63,9

81$2

,130

,786

($66

6,80

5)($

302,

453)

($1,

490,

031)

$3,0

86,5

23$3

,479

,934

($39

3,41

1)($

1,88

3,44

2)

Jul-

17($

10,9

42,5

72)

$9,7

49,7

76$9

,025

,589

$724

,187

($10

,218

,385

)($

302,

453)

$1,7

60,2

50$1

,495

,265

$264

,985

($37

,468

)($

1,88

3,44

2)$3

,331

,598

$2,9

35,1

79$3

96,4

19($

1,48

7,02

3)

Aug

-17

($10

,218

,385

)$9

,916

,492

$8,2

85,8

17$1

,630

,675

($8,

587,

710)

($37

,468

)$1

,757

,678

$1,4

07,2

32$3

50,4

46$3

12,9

79($

1,48

7,02

3)$3

,323

,419

$2,7

46,7

67$5

76,6

53($

910,

370)

Sep

-17

($8,

587,

710)

$8,4

53,6

37$7

,827

,579

$626

,058

($7,

961,

652)

$312

,979

$1,6

49,4

95$1

,481

,629

$167

,865

$480

,844

($91

0,37

0)$3

,194

,910

$2,8

24,4

67$3

70,4

43($

539,

927)

Oct

-17

($7,

961,

652)

$6,9

00,6

52$6

,159

,110

$741

,542

($7,

220,

110)

$480

,844

$1,4

50,3

18$8

55,1

59$5

95,1

59$1

,076

,003

($53

9,92

7)$3

,072

,546

$2,2

21,5

66$8

50,9

81$3

11,0

54

Nov

-17

($7,

220,

110)

$6,9

94,1

09$7

,221

,727

($22

7,61

8)($

7,44

7,72

8)$1

,076

,003

$1,4

44,3

61$1

,071

,274

$373

,087

$1,4

49,0

90$3

11,0

54$2

,976

,288

$2,3

10,7

92$6

65,4

96$9

76,5

49

Dec

-17

($7,

447,

728)

$7,4

26,3

63$7

,667

,714

($24

1,35

2)($

7,68

9,08

0)$1

,449

,090

$1,4

54,1

85$1

,181

,773

$272

,412

$1,7

21,5

03$9

76,5

49$2

,765

,986

$2,5

43,6

06$2

22,3

79$1

,198

,929

Jan-

18($

7,68

9,08

0)$5

,530

,194

$0$5

,530

,194

($2,

158,

886)

$1,7

21,5

03$1

,043

,839

$0$1

,043

,839

$2,7

65,3

42$1

,198

,929

$1,7

89,2

54$0

$1,7

89,2

54$2

,988

,182

$90,

351,

954

$89,

929,

352

$422

,602

$17,

943,

367

$14,

773,

825

$3,1

69,5

43$3

4,74

5,77

4$3

0,89

4,38

7$3

,851

,388

Adj

ustm

ents

:A

djus

tmen

ts:

Adj

ustm

ents

:

End

ing

Bal

ance

Ove

r/(U

nder

) In

curr

ed D

urin

g 20

15($

22,8

33)

End

ing

Bal

ance

Ove

r/(U

nder

) In

curr

ed D

urin

g 20

15$5

,674

End

ing

Bal

ance

Ove

r/(U

nder

) In

curr

ed D

urin

g 20

15($

8,16

5)

End

ing

Bal

ance

Pri

or to

App

lica

tion

of

Inte

rest

($2,

181,

718)

End

ing

Bal

ance

Pri

or to

App

lica

tion

of

Inte

rest

$2,7

71,0

16E

ndin

g B

alan

ce P

rior

to A

ppli

cati

on o

f In

tere

st$2

,980

,017

Inte

rest

($33

,610

)In

tere

st$2

4,24

3In

tere

st$2

3,91

6

End

ing

Bal

ance

Inc

ludi

ng I

nter

est

($2,

215,

328)

End

ing

Bal

ance

Inc

ludi

ng I

nter

est

$2,7

95,2

59E

ndin

g B

alan

ce I

nclu

ding

Int

eres

t$3

,003

,933

Ove

r/(U

nder

)O

ver/

(Und

er)

Ove

r/(U

nder

)

Beg

inni

ngM

onth

lyE

ndin

gB

egin

ning

Mon

thly

End

ing

Beg

inni

ngM

onth

lyE

ndin

g

Mon

thB

alan

ceR

even

ueE

xpen

seO

ver/

(Und

er)

Bal

ance

Bal

ance

Rev

enue

Exp

ense

Ove

r/(U

nder

)B

alan

ceB

alan

ceR

even

ueE

xpen

seO

ver/

(Und

er)

Bal

ance

(a)

(b)

(c)

(d)

(e)

(a)

(b)

(c)

(d)

(e)

(a)

(b)

(c)

(d)

(e)

Jan-

17($

1,24

1,47

1)$2

,091

,384

$3,5

72,6

95($

1,48

1,31

2)($

2,72

2,78

3)($

298,

431)

$305

,982

$807

,689

($50

1,70

7)($

800,

138)

($41

,388

)$2

5,11

1$1

41,9

65($

116,

854)

($15

8,24

2)

Feb

-17

($2,

722,

783)

$3,0

89,4

42$3

,106

,075

($16

,633

)($

2,73

9,41

6)($

800,

138)

$732

,459

$721

,698

$10,

760

($78

9,37

8)($

158,

242)

$49,

699

$141

,790

($92

,091

)($

250,

333)

Mar

-17

($2,

739,

416)

$3,2

10,1

05$3

,435

,762

($22

5,65

8)($

2,96

5,07

4)($

789,

378)

$684

,489

$806

,307

($12

1,81

8)($

911,

196)

($25

0,33

3)$4

4,36

6$1

34,4

16($

90,0

50)

($34

0,38

3)

Apr

-17

($2,

965,

074)

$3,5

18,0

21$3

,274

,681

$243

,339

($2,

721,

735)

($91

1,19

6)$7

51,6

61$7

71,8

05($

20,1

43)

($93

1,33

9)($

340,

383)

$37,

035

$153

,576

($11

6,54

0)($

456,

923)

May

-17

($2,

721,

735)

$3,8

78,4

37$4

,038

,729

($16

0,29

2)($

2,88

2,02

7)($

931,

339)

$718

,058

$895

,926

($17

7,86

8)($

1,10

9,20

7)($

456,

923)

($35

,017

)$3

92($

35,4

09)

($49

2,33

2)

Jun-

17($

2,88

2,02

7)$4

,136

,379

$4,6

21,7

38($

485,

359)

($3,

367,

386)

($1,

109,

207)

$908

,109

$1,1

80,0

94($

271,

985)

($1,

381,

192)

($49

2,33

2)$1

12,1

06$3

75$1

11,7

31($

380,

601)

Jul-

17($

3,36

7,38

6)$4

,358

,625

$3,8

66,1

54$4

92,4

70($

2,87

4,91

5)($

1,38

1,19

2)$8

86,9

84$9

38,4

51($

51,4

68)

($1,

432,

660)

($38

0,60

1)$5

9,03

7$3

29$5

8,70

7($

321,

894)

Aug

-17

($2,

874,

915)

$4,4

04,8

73$3

,813

,029

$591

,844

($2,

283,

071)

($1,

432,

660)

$921

,622

$817

,092

$104

,530

($1,

328,

130)

($32

1,89

4)$4

5,60

4$3

34$4

5,27

0($

276,

624)

Sep

-17

($2,

283,

071)

$4,1

01,7

36$3

,945

,606

$156

,130

($2,

126,

941)

($1,

328,

130)

$898

,247

$909

,833

($11

,586

)($

1,33

9,71

5)($

276,

624)

$43,

256

$101

,005

($57

,749

)($

334,

372)

Oct

-17

($2,

126,

941)

$4,2

30,3

46$3

,272

,448

$957

,898

($1,

169,

043)

($1,

339,

715)

$925

,958

$861

,048

$64,

910

($1,

274,

805)

($33

4,37

2)$4

4,75

6$1

04,2

60($

59,5

04)

($39

3,87

6)

Nov

-17

($1,

169,

043)

$3,9

27,1

47$3

,328

,655

$598

,492

($57

0,55

1)($

1,27

4,80

5)$8

55,4

83$8

10,0

43$4

5,44

0($

1,22

9,36

5)($

393,

876)

$63,

777

$128

,446

($64

,669

)($

458,

545)

Dec

-17

($57

0,55

1)$3

,888

,081

$3,6

72,9

29$2

15,1

52($

355,

399)

($1,

229,

365)

$690

,962

$887

,336

($19

6,37

3)($

1,42

5,73

9)($

458,

545)

$68,

783

$134

,138

($65

,355

)($

523,

900)

Jan-

18($

355,

399)

$2,3

64,0

56$0

$2,3

64,0

56$2

,008

,657

($1,

425,

739)

$534

,571

$0$5

34,5

71($

891,

167)

($52

3,90

0)$9

7,48

8$0

$97,

488

($42

6,41

1)

$47,

198,

631

$43,

948,

503

$3,2

50,1

29$9

,814

,586

$10,

407,

322

($59

2,73

6)$6

56,0

03$1

,041

,026

($38

5,02

3)A

djus

tmen

ts:

Adj

ustm

ents

:A

djus

tmen

ts:

End

ing

Bal

ance

Ove

r/(U

nder

) In

curr

ed D

urin

g 20

15($

92,9

14)

End

ing

Bal

ance

Ove

r/(U

nder

) In

curr

ed D

urin

g 20

15($

159,

410)

End

ing

Bal

ance

Ove

r/(U

nder

) In

curr

ed D

urin

g 20

15($

165,

055)

End

ing

Bal

ance

Pri

or to

App

lica

tion

of

Inte

rest

$1,9

15,7

43E

ndin

g B

alan

ce P

rior

to A

ppli

cati

on o

f In

tere

st($

1,05

0,57

7)E

ndin

g B

alan

ce P

rior

to A

ppli

cati

on o

f In

tere

st($

591,

467)

Inte

rest

$11,

927

Inte

rest

($11

,434

)In

tere

st($

5,85

2)

End

ing

Bal

ance

Inc

ludi

ng I

nter

est

$1,9

27,6

69E

ndin

g B

alan

ce I

nclu

ding

Int

eres

t($

1,06

2,01

1)E

ndin

g B

alan

ce I

nclu

ding

Int

eres

t($

597,

319)

(a)

Jan.

-17,

Tru

e-U

p of

Nov

. and

Dec

. 201

6 E

xpen

ses;

Feb

.-17

thro

ugh

Jan.

-18,

Col

umn

(e)

from

pre

viou

s m

onth

(b)

Pag

e 3

(c)

Pag

e 4

(d)

Col

umn

(b)

- C

olum

n(c)

(e)

Col

umn

(a)

+ C

olum

n(d)

Rat

e B

-32/

G-3

2R

ate

B-6

2/G

-62/

X-0

1R

ate

S-0

5/S

-06/

S-1

0/S

-14

For

the

Peri

od J

anua

ry 2

017

thro

ugh

Dec

embe

r 20

17

Rat

e A

-16/

A-6

0R

ate

C-0

6R

ate

G-0

2

Tra

nsm

issi

on S

ervi

ce R

econ

cilia

tion

Bas

e R

econ

cilia

tion

- By

Rat

e C

lass


Tra

nsm

issi

on

Tra

nsm

issi

on

Tra

nsm

issi

on

Unc

olle

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leR

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edU

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lect

ible

Rel

ated

Unc

olle

ctib

leR

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ed

Tot

alF

acto

rH

MV

Bas

eT

otal

Fac

tor

HM

VB

ase

Tot

alF

acto

rH

MV

Bas

eM

onth

Rev

enue

Rev

enue

Cre

dit

Rev

enue

Rev

enue

Rev

enue

Cre

dit

Rev

enue

Rev

enue

Rev

enue

Cre

dit

Rev

enue

(a)

(b)

(c)

(d)

(a)

(b)

(c)

(d)

(a)

(b)

(c)

(d)

(1)

Jan-

17$2

,982

,137

$39,

692

$2,9

42,4

46$5

70,7

65$6

,922

$563

,843

$1,0

38,3

84$1

3,42

1($

215)

$1,0

24,7

48F

eb-1

7$6

,627

,308

$88,

168

$6,5

39,1

40$1

,339

,067

$16,

237

$1,3

22,8

30$2

,392

,537

$30,

577

($37

9)$2

,361

,580

Mar

-17

$6,1

60,2

66$8

1,94

5$6

,078

,321

$1,3

02,2

33$1

5,79

2$1

,286

,441

$2,4

50,3

80$3

1,10

5($

521)

$2,4

18,7

54(2

)A

pr-1

7$6

,553

,713

$84,

811

$6,4

68,9

03$1

,405

,742

$16,

402

$1,3

89,3

40$2

,626

,994

$31,

415

($47

2)$2

,595

,107

May

-17

$6,3

11,8

52$7

6,85

0$6

,235

,002

$1,3

72,8

36$1

6,02

9$1

,356

,806

$2,8

36,0

33$3

0,58

2($

388)

$2,8

05,0

63Ju

n-17

$7,2

04,5

06$8

7,58

7$7

,116

,919

$1,4

82,0

45$1

8,06

4$1

,463

,981

$3,1

20,7

25$3

3,67

2($

529)

$3,0

86,5

23Ju

l-17

$9,8

69,7

80$1

20,0

04$9

,749

,776

$1,7

79,9

59$1

9,70

9$1

,760

,250

$3,3

71,0

21$3

8,97

5($

447)

$3,3

31,5

98A

ug-1

7$1

0,03

8,53

0$1

22,0

38$9

,916

,492

$1,7

77,2

54$1

9,57

6$1

,757

,678

$3,3

62,4

42$3

8,53

3($

490)

$3,3

23,4

19S

ep-1

7$8

,557

,689

$104

,052

$8,4

53,6

37$1

,667

,942

$18,

447

$1,6

49,4

95$3

,232

,820

$37,

105

($80

6)$3

,194

,910

Oct

-17

$6,9

85,5

90$8

4,93

8$6

,900

,652

$1,4

66,6

27$1

6,30

9$1

,450

,318

$3,1

07,5

40$3

4,42

9($

565)

$3,0

72,5

46N

ov-1

7$7

,080

,204

$86,

095

$6,9

94,1

09$1

,460

,605

$16,

244

$1,4

44,3

61$3

,009

,625

$32,

821

($51

6)$2

,976

,288

Dec

-17

$7,5

17,7

23$9

1,36

1$7

,426

,363

$1,4

70,7

07$1

6,52

2$1

,454

,185

$2,7

97,7

07$3

1,28

5($

436)

$2,7

65,9

86(3

)Ja

n-18

$5,5

98,0

06$6

7,81

1$5

,530

,194

$1,0

55,5

77$1

1,73

8$1

,043

,839

$1,8

10,0

96$2

0,57

2($

270)

$1,7

89,2

54

Tot

al$9

1,48

7,30

5$1

,135

,351

$0$9

0,35

1,95

4$1

8,15

1,35

7$2

07,9

90$0

$17,

943,

367

$35,

156,

304

$404

,494

($6,

035)

$34,

745,

774

Tra

nsm

issi

on

Tra

nsm

issi

on

Tra

nsm

issi

on

Unc

olle

ctib

leR

elat

edU

ncol

lect

ible

Rel

ated

Unc

olle

ctib

leR

elat

edT

otal

Fac

tor

HM

VB

ase

Tot

alF

acto

rH

MV

Bas

eT

otal

Fac

tor

HM

VB

ase

Mon

thR

even

ueR

even

ueC

redi

tR

even

ueR

even

ueR

even

ueC

redi

tR

even

ueR

even

ueR

even

ueC

redi

tR

even

ue

(a)

(b)

(c)

(d)

(a)

(b)

(c)

(d)

(a)

(b)

(c)

(d)

(1)

Jan-

17$1

,378

,401

$19,

038

($3,

589)

$2,0

91,3

84$3

13,6

80$4

,387

($3,

312)

$305

,982

$25,

641

$530

$25,

111

Feb

-17

$3,1

40,6

62$4

2,81

3($

8,40

7)$3

,089

,442

$750

,800

$10,

446

($7,

895)

$732

,459

$50,

747

$1,0

48$4

9,69

9

Mar

-17

$3,2

62,9

45$4

4,03

8($

8,80

2)$3

,210

,105

$702

,146

$10,

218

($7,

439)

$684

,489

$45,

302

$936

$44,

366

(2)

Apr

-17

$3,5

73,7

59$4

6,25

0($

9,48

8)$3

,518

,021

$770

,546

$11,

071

($7,

814)

$751

,661

$37,

699

$663

$37,

035

May

-17

$3,9

37,3

15$4

8,82

9($

10,0

49)

$3,8

78,4

37$7

35,2

26$1

0,14

9($

7,01

9)$7

18,0

58($

35,9

60)

($94

3)($

35,0

17)

Jun-

17$4

,199

,525

$51,

915

($11

,231

)$4

,136

,379

$929

,929

$12,

786

($9,

034)

$908

,109

$114

,619

$2,5

12$1

12,1

06

Jul-

17$4

,427

,216

$56,

649

($11

,942

)$4

,358

,625

$908

,160

$12,

394

($8,

782)

$886

,984

$60,

250

$1,2

13$5

9,03

7

Aug

-17

$4,4

73,2

49$5

6,97

4($

11,4

02)

$4,4

04,8

73$9

44,0

03$1

3,22

3($

9,15

8)$9

21,6

22$4

6,51

7$9

13$4

5,60

4

Sep

-17

$4,1

65,5

74$5

3,21

4($

10,6

24)

$4,1

01,7

36$9

19,9

59$1

2,82

9($

8,88

3)$8

98,2

47$4

4,09

3$8

37$4

3,25

6

Oct

-17

$4,2

95,2

10$5

3,77

4($

11,0

90)

$4,2

30,3

46$9

48,2

44$1

3,08

9($

9,19

7)$9

25,9

58$4

5,62

2$8

66$4

4,75

6

Nov

-17

$3,9

87,1

04$4

9,50

3($

10,4

53)

$3,9

27,1

47$8

76,3

86$1

2,45

4($

8,44

8)$8

55,4

83$6

5,03

3$1

,256

$63,

777

Dec

-17

$3,9

48,6

42$4

9,96

7($

10,5

93)

$3,8

88,0

81$7

07,8

30$9

,871

($6,

996)

$690

,962

$70,

149

$1,3

67$6

8,78

3

(3)

Jan-

18$2

,400

,811

$30,

602

($6,

152)

$2,3

64,0

56$5

47,7

32$7

,795

($5,

365)

$534

,571

$99,

573

$2,0

85$9

7,48

8

Tot

al$4

7,19

0,41

2$6

03,5

67($

123,

824)

$47,

198,

631

$10,

054,

642

$140

,712

($99

,343

)$9

,814

,586

$669

,285

$13,

282

$0$6

56,0

03

(1)

Ref

lect

s re

venu

e as

soci

ated

wit

h co

nsum

ptio

n on

and

aft

er J

an 1

G-3

2 R

even

ue I

nclu

des

adju

stm

ent o

f $7

35,6

10 to

incr

ease

rev

enue

plu

s in

tere

st a

ssoc

iate

d w

ith

an a

ccou

nt w

hich

was

und

er-b

ille

d du

e to

inco

rrec

t met

er p

rogr

amm

ing

(2)

Col

umn

(b)

refl

ects

unc

olle

ctib

le f

acto

r ch

ange

eff

ecti

ve A

pril

1(3

) R

efle

cts

reve

nue

asso

ciat

ed w

ith

cons

umpt

ion

befo

re J

an 1

(a)

from

mon

thly

rev

enue

rep

orts

(b)

Sch

edul

e A

SC

-15,

pag

e 2

(c)

from

mon

thly

rev

enue

rep

orts

(d)

Col

umn

(a)

- C

olum

n (b

) +

Col

umn

(c)

Rat

e B

-32/

G-3

2R

ate

B-6

2/G

-62/

X-0

1R

ate

SL

Rev

enue

By

Rat

e C

lass

Rat

e A

-16/

A-6

0R

ate

C-0

6R

ate

G-0

2

Tra

nsm

issi

on S

ervi

ce R

econ

cilia

tion

For

the

Peri

od J

anua

ry 2

017

thro

ugh

Dec

embe

r 20

17


NEPOOL NEP Other ISO Total

PTF Non-PTF ISO Regional Administrative Transmission

Expenses Expenses Charges Expenses Expense(a) (b) (c) (d) (e)

Jan-17 $10,533,643 $4,070,096 $349,359 $246,537 $15,199,636

Feb-17 $9,231,964 $4,005,525 $356,460 $218,602 $13,812,551

Mar-17 $9,073,982 $4,883,843 $375,414 $214,310 $14,547,548

Apr-17 $8,346,806 $4,104,055 $312,425 $197,600 $12,960,885

May-17 $11,064,572 $5,435,470 $370,825 $259,645 $17,130,512

Jun-17 $15,002,213 $4,734,804 $420,665 $332,218 $20,489,900

Jul-17 $14,875,570 $2,729,946 $419,371 $236,081 $18,260,968

Aug-17 $13,568,182 $2,815,806 $387,823 $298,460 $17,070,271

Sep-17 $12,654,036 $3,782,793 $375,800 $277,489 $17,090,118

Oct-17 $9,461,126 $3,494,232 $308,761 $209,472 $13,473,591

Nov-17 $9,431,877 $4,920,356 $308,762 $209,943 $14,870,938

(1) Dec-17 $11,093,283 $4,441,110 $367,063 $186,039 $16,087,495

Total $134,337,254 $49,418,036 $4,352,728 $2,886,397 $190,994,415

(1)

(a) - (d) per monthly NEP and ISO Bills

(e) sum of columns (a) - (d)

A-16/A60 C-06 G-02 B-32 / G-32 B-62/G-62/X-01 S-05/ S-06 /S-10 / S-14 Total

(f) (g) (h) (i) (j) (k) (l)

Jan-17 $7,233,720 $1,073,651 $2,369,917 $3,572,695 $807,689 $141,965 $15,199,636

Feb-17 $6,754,422 $908,844 $2,179,722 $3,106,075 $721,698 $141,790 $13,812,551

Mar-17 $6,968,717 $939,558 $2,262,787 $3,435,762 $806,307 $134,416 $14,547,548

Apr-17 $5,782,969 $821,449 $2,156,406 $3,274,681 $771,805 $153,576 $12,960,885

May-17 $7,925,015 $1,407,205 $2,863,244 $4,038,729 $895,926 $392 $17,130,512

Jun-17 $9,076,973 $2,130,786 $3,479,934 $4,621,738 $1,180,094 $375 $20,489,900

Jul-17 $9,025,589 $1,495,265 $2,935,179 $3,866,154 $938,451 $329 $18,260,968

Aug-17 $8,285,817 $1,407,232 $2,746,767 $3,813,029 $817,092 $334 $17,070,271

Sep-17 $7,827,579 $1,481,629 $2,824,467 $3,945,606 $909,833 $101,005 $17,090,118

Oct-17 $6,159,110 $855,159 $2,221,566 $3,272,448 $861,048 $104,260 $13,473,591

Nov-17 $7,221,727 $1,071,274 $2,310,792 $3,328,655 $810,043 $128,446 $14,870,938

Dec-17 $7,667,714 $1,181,773 $2,543,606 $3,672,929 $887,336 $134,138 $16,087,495

Total $89,929,352 $14,773,825 $30,894,387 $43,948,503 $10,407,322 $1,041,026 $190,994,415

(f)

(g)

(h)

(i)

(j)

(k)

(l)

Annual Expense


Transmission Expense by Rate Class

estimated

Column (e) x Page 5, column (n)

sum of columns (f) through (k)

Column (e) x Page 5, column (i)

Column (e) x Page 5, column (j)

Column (e) x Page 5, column (k)

Column (e) x Page 5, column (l)

Column (e) x Page 5, column (m)


S-05 / S-06Total A-16/A60 C-06 G-02 B-32 / G-32 S-10 / S-14(a) (b) (c) (d) (e) (f) (g)

Jan-2017 1,117,002 531,597 78,901 174,162 262,553 59,356 10,433Feb-2017 1,061,255 518,960 69,829 167,474 238,648 55,450 10,894Mar-2017 1,011,192 484,392 65,308 157,285 238,818 56,046 9,343Apr-2017 860,841 384,095 54,559 143,225 217,499 51,262 10,200

May-2017 1,224,551 566,509 100,592 204,675 288,703 64,044 28Jun-2017 1,473,401 652,713 153,222 250,237 332,343 84,859 27Jul-2017 1,496,485 739,646 122,537 240,538 316,831 76,906 27

Aug-2017 1,380,698 670,183 113,821 222,167 308,410 66,089 27Sep-2017 1,321,572 605,303 114,574 218,415 305,112 70,357 7,811Oct-2017 943,772 431,421 59,900 155,612 229,222 60,313 7,303

Nov-2017 1,024,718 497,631 73,819 159,231 229,369 55,818 8,851Dec-2017* 1,151,117 548,652 84,560 182,004 262,811 63,492 9,598

Total 14,066,603 6,631,102 1,091,623 2,275,025 3,230,319 763,992 74,542

*December 2017 Coincident Peak Data Not available at time of filing - December 2016 Coincident Peak Loads used as a proxy

Coincident Peak Data - kW as Percentage of Total Monthly kWRate Class Contribution as a Percentage of Total

S-05 / S-06Total A-16/A60 C-06 G-02 B-32 / G-32 S-10 / S-14(h) (i) (j) (k) (l) (m) (n)

Jan-2017 100.0% 47.6% 7.1% 15.6% 23.5% 5.3% 0.9%Feb-2017 100.0% 48.9% 6.6% 15.8% 22.5% 5.2% 1.0%Mar-2017 100.0% 47.9% 6.5% 15.6% 23.6% 5.5% 0.9%Apr-2017 100.0% 44.6% 6.3% 16.6% 25.3% 6.0% 1.2%

May-2017 100.0% 46.3% 8.2% 16.7% 23.6% 5.2% 0.0%Jun-2017 100.0% 44.3% 10.4% 17.0% 22.6% 5.8% 0.0%Jul-2017 100.0% 49.4% 8.2% 16.1% 21.2% 5.1% 0.0%

Aug-2017 100.0% 48.5% 8.2% 16.1% 22.3% 4.8% 0.0%Sep-2017 100.0% 45.8% 8.7% 16.5% 23.1% 5.3% 0.6%Oct-2017 100.0% 45.7% 6.3% 16.5% 24.3% 6.4% 0.8%

Nov-2017 100.0% 48.6% 7.2% 15.5% 22.4% 5.4% 0.9%Dec-2017* 100.0% 47.7% 7.3% 15.8% 22.8% 5.5% 0.8%

Total 100.0% 47.1% 7.8% 16.2% 23.0% 5.4% 0.5%

B-62/ G-62/ X-01

Development of Coincident Peak Allocation Factor


B-62/ G-62/ X-01


Incu

rred

:Ja

nuar

y 1,

201

5 th

roug

h D

ecem

ber

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015

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thro

ugh

Mar

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1, 2

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ing

End

ing

End

ing

Ove

r/(U

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)O

ver/

(Und

er)

Ove

r/(U

nder

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(Und

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Inte

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w/ I

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(Ref

und)

Bal

ance

Bal

ance

Rat

eIn

tere

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/ Int

eres

tB

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ce(R

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d)B

alan

ceB

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ceR

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Inte

rest

w/ I

nter

est

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(a)

(b)

(c)

(d)

(e)

(f)

(g)

Jan-

16($

2,25

6,06

9)($

2,25

6,06

9)($

2,25

6,06

9)2.

54%

($4,

775)

($2,

260,

844)

$431

,651

$431

,651

$431

,651

2.54

%$9

14$4

32,5

64($

96,2

71)

($96

,271

)($

96,2

71)

2.54

%($

204)

($96

,475

)F

eb-1

6($

2,26

0,84

4)($

2,26

0,84

4)($

2,26

0,84

4)2.

54%

($4,

785)

($2,

265,

630)

$432

,564

$432

,564

$432

,564

2.54

%$9

16$4

33,4

80($

96,4

75)

($96

,475

)($

96,4

75)

2.54

%($

204)

($96

,679

)M

ar-1

6($

2,26

5,63

0)($

2,26

5,63

0)($

2,26

5,63

0)2.

14%

($4,

040)

($2,

269,

670)

$433

,480

$433

,480

$433

,480

2.14

%$7

73$4

34,2

53($

96,6

79)

($96

,679

)($

96,6

79)

2.14

%($

172)

($96

,852

)(1

)A

pr-1

6($

2,26

9,67

0)$7

3,78

7($

2,19

5,88

3)($

2,23

2,77

6)2.

14%

($3,

982)

($2,

199,

865)

$434

,253

($16

,189

)$4

18,0

64$4

26,1

592.

14%

$760

$418

,824

($96

,852

)$2

,366

($94

,485

)($

95,6

68)

2.14

%($

171)

($94

,656

)M

ay-1

6($

2,19

9,86

5)$1

37,8

54($

2,06

2,01

1)($

2,13

0,93

8)2.

14%

($3,

800)

($2,

065,

811)

$418

,824

($29

,665

)$3

89,1

60$4

03,9

922.

14%

$720

$389

,880

($94

,656

)$6

,390

($88

,266

)($

91,4

61)

2.14

%($

163)

($88

,429

)Ju

n-16

($2,

065,

811)

$177

,618

($1,

888,

193)

($1,

977,

002)

2.14

%($

3,52

6)($

1,89

1,71

8)$3

89,8

80($

34,9

59)

$354

,921

$372

,401

2.14

%$6

64$3

55,5

85($

88,4

29)

$7,7

07($

80,7

22)

($84

,576

)2.

14%

($15

1)($

80,8

73)

Jul-

16($

1,89

1,71

8)$2

20,3

19($

1,67

1,39

9)($

1,78

1,55

9)2.

14%

($3,

177)

($1,

674,

576)

$355

,585

($39

,506

)$3

16,0

79$3

35,8

322.

14%

$599

$316

,678

($80

,873

)$8

,613

($72

,260

)($

76,5

66)

2.14

%($

137)

($72

,396

)A

ug-1

6($

1,67

4,57

6)$2

70,5

89($

1,40

3,98

7)($

1,53

9,28

2)2.

14%

($2,

745)

($1,

406,

732)

$316

,678

($42

,878

)$2

73,8

00$2

95,2

392.

14%

$527

$274

,327

($72

,396

)$8

,875

($63

,521

)($

67,9

59)

2.14

%($

121)

($63

,643

)S

ep-1

6($

1,40

6,73

2)$2

38,9

74($

1,16

7,75

9)($

1,28

7,24

6)2.

14%

($2,

296)

($1,

170,

054)

$274

,327

($41

,468

)$2

32,8

59$2

53,5

932.

14%

$452

$233

,311

($63

,643

)$8

,942

($54

,701

)($

59,1

72)

2.14

%($

106)

($54

,806

)O

ct-1

6($

1,17

0,05

4)$1

66,6

66($

1,00

3,38

9)($

1,08

6,72

1)2.

14%

($1,

938)

($1,

005,

327)

$233

,311

($33

,736

)$1

99,5

75$2

16,4

432.

14%

$386

$199

,961

($54

,806

)$7

,352

($47

,455

)($

51,1

31)

2.14

%($

91)

($47

,546

)N

ov-1

6($

1,00

5,32

7)$1

52,5

60($

852,

767)

($92

9,04

7)2.

14%

($1,

657)

($85

4,42

3)$1

99,9

61($

30,5

46)

$169

,415

$184

,688

2.14

%$3

29$1

69,7

44($

47,5

46)

$6,6

81($

40,8

65)

($44

,206

)2.

14%

($79

)($

40,9

44)

Dec

-16

($85

4,42

3)$1

76,1

50($

678,

274)

($76

6,34

8)2.

14%

($1,

367)

($67

9,64

0)$1

69,7

44($

32,9

98)

$136

,746

$153

,245

2.14

%$2

73$1

37,0

19($

40,9

44)

$6,9

56($

33,9

88)

($37

,466

)2.

14%

($67

)($

34,0

55)

Jan-

17($

679,

640)

$201

,935

($47

7,70

6)($

578,

673)

2.14

%($

1,03

2)($

478,

738)

$137

,019

($38

,069

)$9

8,95

0$1

17,9

852.

14%

$210

$99,

161

($34

,055

)$7

,540

($26

,515

)($

30,2

85)

2.14

%($

54)

($26

,569

)F

eb-1

7($

478,

738)

$185

,859

($29

2,87

8)($

385,

808)

2.14

%($

688)

($29

3,56

6)$9

9,16

1($

37,0

09)

$62,

152

$80,

657

2.14

%$1

44$6

2,29

6($

26,5

69)

$7,1

35($

19,4

34)

($23

,001

)2.

14%

($41

)($

19,4

75)

Mar

-17

($29

3,56

6)$1

73,0

89($

120,

477)

($20

7,02

2)1.

84%

($31

7)($

120,

795)

$62,

296

($36

,061

)$2

6,23

5$4

4,26

61.

84%

$68

$26,

303

($19

,475

)$7

,253

($12

,222

)($

15,8

48)

1.84

%($

24)

($12

,246

)(2

)A

pr-1

7($

120,

795)

$98,

072

($22

,723

)($

71,7

59)

1.84

%($

110)

($22

,833

)$2

6,30

3($

20,6

53)

$5,6

50$1

5,97

61.

84%

$25

$5,6

74($

12,2

46)

$4,0

96($

8,15

0)($

10,1

98)

1.84

%($

16)

($8,

165)

$2,2

73,4

71($

433,

736)

$89,

906

End

ing

End

ing

End

ing

Ove

r/(U

nder

)O

ver/

(Und

er)

Ove

r/(U

nder

)O

ver/

(Und

er)

Ove

r/(U

nder

)O

ver/

(Und

er)

Beg

inni

ngC

harg

e/E

ndin

gIn

tere

stIn

tere

stR

ecov

ery

Beg

inni

ngC

harg

e/E

ndin

gIn

tere

stIn

tere

stR

ecov

ery

Beg

inni

ngC

harg

e/E

ndin

gIn

tere

stIn

tere

stR

ecov

ery

Mon

thB

alan

ce(R

efun

d)B

alan

ceB

alan

ceR

ate

Inte

rest

w/ I

nter

est

Bal

ance

(Ref

und)

Bal

ance

Bal

ance

Rat

eIn

tere

stw

/ Int

eres

tB

alan

ce(R

efun

d)B

alan

ceB

alan

ceR

ate

Inte

rest

w/ I

nter

est

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(a)

(b)

(c)

(d)

(e)

(f)

(g)

Jan-

16($

2,31

2,80

3)($

2,31

2,80

3)($

2,31

2,80

3)2.

54%

($4,

895)

($2,

317,

699)

($1,

221,

021)

($1,

221,

021)

($1,

221,

021)

2.54

%($

2,58

4)($

1,22

3,60

5)($

498,

136)

($49

8,13

6)($

498,

136)

2.54

%($

1,05

4)($

499,

190)

Feb

-16

($2,

317,

699)

($2,

317,

699)

($2,

317,

699)

2.54

%($

4,90

6)($

2,32

2,60

4)($

1,22

3,60

5)($

1,22

3,60

5)($

1,22

3,60

5)2.

54%

($2,

590)

($1,

226,

195)

($49

9,19

0)($

499,

190)

($49

9,19

0)2.

54%

($1,

057)

($50

0,24

7)M

ar-1

6($

2,32

2,60

4)($

2,32

2,60

4)($

2,32

2,60

4)2.

14%

($4,

142)

($2,

326,

746)

($1,

226,

195)

($1,

226,

195)

($1,

226,

195)

2.14

%($

2,18

7)($

1,22

8,38

2)($

500,

247)

($50

0,24

7)($

500,

247)

2.14

%($

892)

($50

1,13

9)(1

)A

pr-1

6($

2,32

6,74

6)$8

1,44

9($

2,24

5,29

7)($

2,28

6,02

2)2.

14%

($4,

077)

($2,

249,

374)

($1,

228,

382)

$47,

370

($1,

181,

012)

($1,

204,

697)

2.14

%($

2,14

8)($

1,18

3,16

0)($

501,

139)

$13,

229

($48

7,91

0)($

494,

524)

2.14

%($

882)

($48

8,79

2)M

ay-1

6($

2,24

9,37

4)$1

69,7

15($

2,07

9,66

0)($

2,16

4,51

7)2.

14%

($3,

860)

($2,

083,

520)

($1,

183,

160)

$79,

827

($1,

103,

333)

($1,

143,

246)

2.14

%($

2,03

9)($

1,10

5,37

1)($

488,

792)

$22,

696

($46

6,09

6)($

477,

444)

2.14

%($

851)

($46

6,94

7)Ju

n-16

($2,

083,

520)

$196

,986

($1,

886,

534)

($1,

985,

027)

2.14

%($

3,54

0)($

1,89

0,07

4)($

1,10

5,37

1)$8

8,93

1($

1,01

6,44

1)($

1,06

0,90

6)2.

14%

($1,

892)

($1,

018,

333)

($46

6,94

7)$2

1,74

5($

445,

203)

($45

6,07

5)2.

14%

($81

3)($

446,

016)

Jul-

16($

1,89

0,07

4)$1

99,5

01($

1,69

0,57

2)($

1,79

0,32

3)2.

14%

($3,

193)

($1,

693,

765)

($1,

018,

333)

$91,

802

($92

6,53

0)($

972,

431)

2.14

%($

1,73

4)($

928,

265)

($44

6,01

6)$2

3,21

6($

422,

800)

($43

4,40

8)2.

14%

($77

5)($

423,

575)

Aug

-16

($1,

693,

765)

$211

,849

($1,

481,

916)

($1,

587,

841)

2.14

%($

2,83

2)($

1,48

4,74

8)($

928,

265)

$98,

495

($82

9,76

9)($

879,

017)

2.14

%($

1,56

8)($

831,

337)

($42

3,57

5)$2

2,94

0($

400,

635)

($41

2,10

5)2.

14%

($73

5)($

401,

370)

Sep

-16

($1,

484,

748)

$215

,188

($1,

269,

560)

($1,

377,

154)

2.14

%($

2,45

6)($

1,27

2,01

6)($

831,

337)

$99,

500

($73

1,83

7)($

781,

587)

2.14

%($

1,39

4)($

733,

231)

($40

1,37

0)$2

7,32

9($

374,

041)

($38

7,70

6)2.

14%

($69

1)($

374,

733)

Oct

-16

($1,

272,

016)

$185

,953

($1,

086,

063)

($1,

179,

040)

2.14

%($

2,10

3)($

1,08

8,16

6)($

733,

231)

$92,

809

($64

0,42

1)($

686,

826)

2.14

%($

1,22

5)($

641,

646)

($37

4,73

3)$3

2,05

4($

342,

678)

($35

8,70

5)2.

14%

($64

0)($

343,

318)

Nov

-16

($1,

088,

166)

$176

,304

($91

1,86

2)($

1,00

0,01

4)2.

14%

($1,

783)

($91

3,64

5)($

641,

646)

$83,

196

($55

8,45

0)($

600,

048)

2.14

%($

1,07

0)($

559,

520)

($34

3,31

8)$3

2,99

8($

310,

320)

($32

6,81

9)2.

14%

($58

3)($

310,

903)

Dec

-16

($91

3,64

5)$1

79,6

30($

734,

015)

($82

3,83

0)2.

14%

($1,

469)

($73

5,48

4)($

559,

520)

$89,

492

($47

0,02

8)($

514,

774)

2.14

%($

918)

($47

0,94

6)($

310,

903)

$35,

794

($27

5,10

9)($

293,

006)

2.14

%($

523)

($27

5,63

2)Ja

n-17

($73

5,48

4)$1

86,5

99($

548,

885)

($64

2,18

5)2.

14%

($1,

145)

($55

0,03

0)($

470,

946)

$89,

006

($38

1,94

0)($

426,

443)

2.14

%($

760)

($38

2,70

1)($

275,

632)

$39,

434

($23

6,19

7)($

255,

915)

2.14

%($

456)

($23

6,65

4)F

eb-1

7($

550,

030)

$174

,445

($37

5,58

5)($

462,

808)

2.14

%($

825)

($37

6,41

1)($

382,

701)

$88,

047

($29

4,65

4)($

338,

677)

2.14

%($

604)

($29

5,25

8)($

236,

654)

$32,

416

($20

4,23

8)($

220,

446)

2.14

%($

393)

($20

4,63

1)M

ar-1

7($

376,

411)

$179

,163

($19

7,24

8)($

286,

829)

1.84

%($

440)

($19

7,68

8)($

295,

258)

$86,

122

($20

9,13

5)($

252,

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33%

$693

$357

,386

($57

,834

)$0

($57

,834

)($

57,8

34)

2.33

%($

112)

($57

,946

)($

138,

425)

$0($

138,

425)

($13

8,42

5)2.

33%

($26

9)($

138,

694)

(2)

Apr

-18

$357

,386

$0$3

57,3

86$3

57,3

862.

33%

$694

$358

,080

($57

,946

)$0

($57

,946

)($

57,9

46)

2.33

%($

113)

($58

,059

)($

138,

694)

$0($

138,

694)

($13

8,69

4)2.

33%

($26

9)($

138,

963)

($1,

222,

833)

$246

,999

$332

,027

(1)

Ref

lect

s kW

hs c

onsu

med

on

and

afte

r to

Apr

il 1

(2)

Ref

lect

s kW

hs c

onsu

med

pri

or to

Apr

il 1

(a)

Sch

edul

e A

SC

-12

Rev

ised

, Pag

e 2

of 7

, Doc

ket N

o. 4

691

(201

7 E

lect

ric

Ret

ail R

ate

Fil

ing)

(b)

from

mon

thly

rev

enue

rep

orts

(c)

Col

umn

(a)

+ C

olum

n (b

)(d

)(C

olum

n (a

) +

Col

umn

(c))

÷ 2

(e)

Cur

rent

Rat

e fo

r C

usto

mer

Dep

osit

s (f

)C

olum

n (d

) x

(C

olum

n (e

) ÷

12)

(g)

Col

umn

(c)

+ C

olum

n (f

)

For

the

Peri

od J

anua

ry 2

017

thro

ugh

Dec

embe

r 20

17T

rans

mis

sion

Ser

vice

Rec

onci

liatio

n

Rat

e B

-32/

G-3

2R

ate

B-6

2/G

-62/

X-0

1R

ate

SL

Stat

us o

f Pri

or P

erio

d O

ver/

(Und

er) C

olle

ctio

n

Rat

e A

-16/

A-6

0R

ate

C-0

6R

ate

G-0

2


Schedule A

SC-13




Schedule ASC-13

Calculation of Proposed Transmission Adjustment Factors

Cal

cula

tion

of

Tra

nsm

issi

on A

djus

tmen

t Fac

tor

Lin

e N

o.T

otal

A16

/A60

C06

G02

B32

/G32

B62

/G62

/X01

SL

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(1)

Tra

nsm

issi

on O

ver/

(Und

er)

Rec

over

y$3

,852

,203

($2,

215,

328)

$2,7

95,2

59$3

,003

,933

$1,9

27,6

69($

1,06

2,01

1)($

597,

319)

(2)

Plu

s: E

stim

ated

Int

eres

t Dur

ing

the

Ref

und/

Rec

over

y P

erio

d$6

4,75

8($

37,2

41)

$46,

990

$50,

498

$32,

405

($17

,853

)($

10,0

41)

(3)

Tot

al T

rans

mis

sion

Ove

r(U

nder

) R

ecov

ery

(inc

ludi

ng in

tere

st)

$3,9

16,9

61($

2,25

2,56

9)$2

,842

,249

$3,0

54,4

31$1

,960

,075

($1,

079,

864)

($60

7,36

0)

(4)

For

ecas

ted

kWhs

Dur

ing

Rec

over

y P

erio

d 7,

292,

662,

088

2,95

2,21

7,33

9

59

8,40

6,29

1

1,29

0,64

4,35

3

1,

958,

411,

647

446,

170,

232

46

,812

,226

(5)

Pro

pose

d T

rans

mis

sion

Adj

ustm

ent C

harg

e/(C

redi

t)

$0.0

0076

($0.

0047

4)($

0.00

236)

($0.

0010

0)$0

.002

42$0

.012

97

(1)

Sch

edul

e A

SC

-12,

pag

e 2

(2)

page

2(3

)L

ine

(1)

+ L

ine

(2)

(4)

per

Com

pany

for

ecas

t(5

)L

ine

3 ÷

Lin

e 4,

trun

cate

d to

fiv

e de

cim

al p

lace

s

Tra

nsm

issi

on S

ervi

ce R

econ

cili

atio

nF

or t

he

Per

iod

Jan

uar

y 20

17 t

hro

ugh

Dec

emb

er 2

017

For

the

Per

iod

Apr

il 1

, 201

8 th

roug

h M

arch

31,

201

9


Rate A-16/A-60 Rate C-06 Rate G-02

Interest Beginning (Charge)/ Ending Beginning (Charge)/ Ending Beginning (Charge)/ EndingMonth Rate Balance Recovery Balance Interest Balance Recovery Balance Interest Balance Recovery Balance Interest

(a) (b) (c) (d) (e) (b) (c) (d) (e) (b) (c) (d) (e)

Jan-17 1.84% ($2,215,328) ($2,215,328) ($3,397) $2,795,259 $2,795,259 $4,286 $3,003,933 $3,003,933 $4,606Feb-17 1.84% ($2,218,725) ($2,218,725) ($3,402) $2,799,545 $2,799,545 $4,293 $3,008,539 $3,008,539 $4,613Mar-17 2.33% ($2,222,127) ($2,222,127) ($4,315) $2,803,838 $2,803,838 $5,444 $3,013,152 $3,013,152 $5,851Apr-17 2.33% ($2,226,442) ($185,537) ($2,040,905) ($4,143) $2,809,282 $234,107 $2,575,175 $5,227 $3,019,002 $251,584 $2,767,419 $5,618May-17 2.33% ($2,045,048) ($185,913) ($1,859,134) ($3,790) $2,580,403 $234,582 $2,345,821 $4,783 $2,773,036 $252,094 $2,520,942 $5,140Jun-17 2.33% ($1,862,925) ($186,292) ($1,676,632) ($3,436) $2,350,603 $235,060 $2,115,543 $4,336 $2,526,082 $252,608 $2,273,474 $4,660Jul-17 2.33% ($1,680,069) ($186,674) ($1,493,394) ($3,081) $2,119,879 $235,542 $1,884,337 $3,887 $2,278,133 $253,126 $2,025,007 $4,178Aug-17 2.33% ($1,496,475) ($187,059) ($1,309,416) ($2,724) $1,888,224 $236,028 $1,652,196 $3,437 $2,029,185 $253,648 $1,775,537 $3,694Sep-17 2.33% ($1,312,140) ($187,449) ($1,124,691) ($2,366) $1,655,633 $236,519 $1,419,114 $2,985 $1,779,231 $254,176 $1,525,055 $3,208Oct-17 2.33% ($1,127,057) ($187,843) ($939,214) ($2,006) $1,422,099 $237,017 $1,185,083 $2,531 $1,528,263 $254,710 $1,273,552 $2,720Nov-17 2.33% ($941,220) ($188,244) ($752,976) ($1,645) $1,187,614 $237,523 $950,091 $2,075 $1,276,272 $255,254 $1,021,018 $2,230Dec-17 2.33% ($754,621) ($188,655) ($565,966) ($1,282) $952,166 $238,042 $714,125 $1,618 $1,023,248 $255,812 $767,436 $1,738Jan-18 2.33% ($567,248) ($189,083) ($378,165) ($918) $715,743 $238,581 $477,162 $1,158 $769,175 $256,392 $512,783 $1,245Feb-18 2.33% ($379,083) ($189,542) ($189,542) ($552) $478,320 $239,160 $239,160 $697 $514,028 $257,014 $257,014 $749Mar-18 2.33% ($190,094) ($190,094) ($185) $239,856 $239,856 $0 $233 $257,762 $257,762 $0 $250

($37,241) $46,990 $50,498

Rate B-32/G-32 Rate B-62/G-62/X-01 Rate SL

Interest Beginning (Charge)/ Ending Beginning (Charge)/ Ending Beginning (Charge)/ EndingMonth Rate Balance Recovery Balance Interest Balance Recovery Balance Interest Balance Recovery Balance Interest

(d) (b) (c) (d) (e) (b) (c) (d) (e) (b) (c) (d) (e)

Jan-17 1.84% $1,927,669 $1,927,669 $2,956 ($1,062,011) ($1,062,011) ($1,628) ($597,319) ($597,319) ($916)Feb-17 1.84% $1,930,625 $1,930,625 $2,960 ($1,063,640) ($1,063,640) ($1,631) ($598,235) ($598,235) ($917)Mar-17 2.33% $1,933,585 $1,933,585 $3,754 ($1,065,271) ($1,065,271) ($2,068) ($599,152) ($599,152) ($1,163)Apr-17 2.33% $1,937,340 $161,445 $1,775,895 $3,605 ($1,067,339) ($88,945) ($978,394) ($1,986) ($600,315) ($50,026) ($550,289) ($1,117)May-17 2.33% $1,779,500 $161,773 $1,617,727 $3,298 ($980,380) ($89,125) ($891,255) ($1,817) ($551,406) ($50,128) ($501,278) ($1,022)Jun-17 2.33% $1,621,025 $162,103 $1,458,923 $2,990 ($893,072) ($89,307) ($803,765) ($1,647) ($502,300) ($50,230) ($452,070) ($927)Jul-17 2.33% $1,461,913 $162,435 $1,299,478 $2,681 ($805,412) ($89,490) ($715,922) ($1,477) ($452,997) ($50,333) ($402,664) ($831)Aug-17 2.33% $1,302,159 $162,770 $1,139,389 $2,370 ($717,399) ($89,675) ($627,724) ($1,306) ($403,495) ($50,437) ($353,058) ($734)Sep-17 2.33% $1,141,759 $163,108 $978,651 $2,059 ($629,030) ($89,861) ($539,168) ($1,134) ($353,792) ($50,542) ($303,251) ($638)Oct-17 2.33% $980,709 $163,452 $817,258 $1,746 ($540,303) ($90,050) ($450,252) ($962) ($303,888) ($50,648) ($253,240) ($541)Nov-17 2.33% $819,003 $163,801 $655,203 $1,431 ($451,214) ($90,243) ($360,971) ($788) ($253,781) ($50,756) ($203,025) ($443)Dec-17 2.33% $656,634 $164,158 $492,475 $1,116 ($361,759) ($90,440) ($271,320) ($615) ($203,468) ($50,867) ($152,601) ($346)Jan-18 2.33% $493,591 $164,530 $329,061 $799 ($271,934) ($90,645) ($181,289) ($440) ($152,947) ($50,982) ($101,965) ($247)Feb-18 2.33% $329,859 $164,930 $164,930 $480 ($181,729) ($90,865) ($90,865) ($265) ($102,212) ($51,106) ($51,106) ($149)Mar-18 2.33% $165,410 $165,410 $0 $161 ($91,129) ($91,129) $0 ($88) ($51,255) ($51,255) $0 ($50)

$32,405 ($17,853) ($10,041)

(a) Current Rate for Customer Deposits (b) Page 1, Line 1(c) For Apr, (Column (b)) ÷ 12. For May, (Column (a)) ÷ 11, etc.(d) Column (a) - Column (b)(5) [(Column (b) + Column (d)) ÷ 2] x (Column (a) ÷ 12)

Calculation of Transmission Adjustment Factor

Interest During the Recovery/Refund Period


For the Period April 1, 2018 through March 31, 2019


Schedule ASC

-14




Schedule ASC-14

Calculation of Proposed Transmission Uncollectible Factors

Tot

alA

16/A

60C

06G

02B

32/G

32B

62/G

62/X

01SL

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(1)

Est

imat

ed B

ase

Tra

nsm

issi

on R

even

ue$2

08,0

83,1

13$9

3,12

2,19

4$1

8,95

5,93

5$3

5,99

8,44

9$4

8,85

4,69

9$1

0,47

7,30

0$6

74,5

36

(2)

Tra

nsm

issi

on S

ervi

ce (

Ove

r)/U

nder

Col

lect

ion

($3,

916,

961)

$2,2

52,5

69($

2,84

2,24

9)($

3,05

4,43

1)($

1,96

0,07

5)$1

,079

,864

$607

,360

(3)

Tra

nsm

issi

on U

ncol

lect

ible

(O

ver)

/Und

er C

olle

ctio

n B

alan

ce

$72,

613

$35,

125

$4,5

43$2

8,91

8$7

79$2

,631

$617

(4)

Tot

al$2

04,2

38,7

66$9

5,40

9,88

8$1

6,11

8,22

9$3

2,97

2,93

6$4

6,89

5,40

4$1

1,55

9,79

5$1

,282

,513

(5)

App

rove

d U

ncol

lect

ible

Rat

e 1.

25%

(6)

Est

imat

ed T

rans

mis

sion

-rel

ated

Unc

olle

ctib

le E

xpen

se$2

,552

,985

$1,1

92,6

24$2

01,4

78$4

12,1

62$5

86,1

93$1

44,4

97$1

6,03

1

(7)

Fore

cast

ed k

Wh

7,29

2,66

2,08

82,

952,

217,

339

598,

406,

291

1,29

0,64

4,35

31,

958,

411,

647

446,

170,

232

46,8

12,2

26

(8)

2018

Tra

nsm

issi

on U

ncol

lect

ible

Fac

tor

per

kWh

$0.0

0040

$0.0

0033

$0.0

0031

$0.0

0029

$0.0

0032

$0.0

0034

(9)

2017

Tra

nsm

issi

on U

ncol

lect

ible

Rec

onci

liat

ion

Fac

tor

$0.0

0001

$0.0

0000

$0.0

0002

$0.0

0000

$0.0

0000

$0.0

0001

(10)

Tra

nsm

issi

on U

ncol

lect

ible

Fac

tor

effe

ctiv

e A

pril

1, 2

018

thro

ugh

Mar

ch 3

1, 2

019

$0.0

0041

$0.0

0033

$0.0

0033

$0.0

0029

$0.0

0032

$0.0

0035

(1)

from

Sch

edul

e A

SC-1

1, p

age

1, li

ne 3

(6)

Lin

e (4

) x

Lin

e (5

)(2

)fr

om S

ched

ule

ASC

-13,

pag

e 1,

line

(3)

(7)

per

Com

pany

for

ecas

t for

the

reco

very

/(re

fund

) pe

riod

(3)

from

Sch

edul

e A

SC-1

5, p

age

1, L

ine

14(8

)L

ine

(6)

÷ L

ine

(7),

trun

cate

d to

fiv

e de

cim

al p

lace

s(4

)L

ine

(1)

+ L

ine

(2)

+ L

ine

(3)

(9)

Sche

dule

ASC

-15,

Pag

e 1,

Lin

e (1

7)(5

)pe

r R

IPU

C D

ocke

t No.

432

3, s

ettl

emen

t agr

eem

ent

(10)

Lin

e (8

) +

Lin

e (9

)

Tra

nsm

issi

on S

ervi

ce U

ncol

lect

ible

Rec

onci

liat

ion

For

the

Per

iod

Janu

ary

2017

thr

ough

Dec

embe

r 20

17

Cal

cula

tion

of

Tra

nsm

issi

on U

ncol

lect

ible

Fac

tor

For

the

Peri

od A

pril

1, 2

018

thro

ugh

Mar

ch 3

1, 2

019


Schedule ASC

-15




Schedule ASC-15

Transmission Uncollectible Factor Reconciliation For the period January 2017 through December 2017

Tot

alA

16/A

60C

06G

02B

32/G

32B

62/G

62/X

01S

L

(1)

Tra

nsm

issi

on U

ncol

lect

ible

Fac

tor

Rev

enue

$2,4

63,5

35$1

,117

,520

$206

,185

$397

,058

$597

,907

$132

,156

$12,

708

Cal

cula

tion

of

Tra

nsm

issi

on U

ncol

lect

ible

Exp

ense

(2)

Act

ual B

ase

Tra

nsm

issi

on R

even

ue D

urin

g R

econ

cili

atio

n P

erio

d$1

99,9

74,7

06$9

0,35

1,95

4$1

7,94

3,36

7$3

4,74

5,77

4$4

6,46

3,02

1$9

,814

,586

$656

,003

(3)

Act

ual T

rans

mis

sion

Adj

ustm

ent F

acto

r R

even

ue D

urin

g R

econ

cili

atio

n P

erio

d($

3,01

8,73

6)$6

7,64

2($

1,68

1,11

6)($

1,83

5,55

6)($

443,

650)

$532

,057

$341

,888

(4)

Act

ual U

ncol

lect

ible

Fac

tor

Rev

enue

Dur

ing

Rec

onci

liat

ion

Per

iod

$2,5

05,3

97$1

,135

,351

$207

,990

$404

,494

$603

,567

$140

,712

$13,

282

(5)

Tot

al A

ctua

l Tra

nsm

issi

on R

elat

ed R

even

ue$1

99,4

61,3

67$9

1,55

4,94

7$1

6,47

0,24

1$3

3,31

4,71

3$4

6,62

2,93

8$1

0,48

7,35

6$1

,011

,173

(6)

Unc

olle

ctib

le F

acto

r1.

25%

1.25

%1.

25%

1.25

%1.

25%

1.25

%1.

25%

(7)

Tra

nsm

issi

on U

ncol

lect

ible

Exp

ense

Inc

urre

d D

urin

g R

econ

cili

atio

n P

erio

d$2

,493

,267

$1,1

44,4

37$2

05,8

78$4

16,4

34$5

82,7

87$1

31,0

92$1

2,64

0

Cal

cula

tion

of

Ove

r/(U

nder

) R

ecov

ery

(8)

Ove

r/(U

nder

) R

ecov

ery

- C

urre

nt R

econ

cili

atio

n P

erio

d($

29,7

32)

($26

,917

)$3

07($

19,3

76)

$15,

120

$1,0

64$6

9

(9)

End

ing

Bal

ance

- P

rior

Rec

onci

liat

ion

Per

iod

($41

,012

)($

7,30

4)($

4,73

3)($

8,79

7)($

15,8

80)

($3,

627)

($66

9)

(10)

Tot

al O

ver/

(Und

er)

Rec

over

y($

70,7

44)

($34

,221

)($

4,42

6)($

28,1

73)

($75

9)($

2,56

3)($

601)

(11)

Inte

rest

($

669)

($32

3)($

42)

($26

6)($

7)($

24)

($6)

(12)

Tra

nsm

issi

on U

ncol

lect

ible

Fac

tor

Ove

r(U

nder

) R

ecov

ery

Incl

. Int

eres

t($

71,4

13)

($34

,545

)($

4,46

8)($

28,4

39)

($76

7)($

2,58

8)($

607)

(13)

Est

imat

ed I

nter

est A

ppli

ed D

urin

g th

e R

ecov

ery

Per

iod

($1,

200)

($58

1)($

75)

($47

8)($

13)

($43

)($

10)

(14)

Tra

nsm

issi

on U

ncol

lect

ible

Fac

tor

Ove

r(U

nder

) R

ecov

ery

($72

,613

)($

35,1

25)

($4,

543)

($28

,918

)($

779)

($2,

631)

($61

7)

Incl

. Int

eres

t Dur

ing

Rec

over

y

Cal

cula

tion

of

Rec

onci

liat

ion

Fac

tor

(15)

Tra

nsm

issi

on U

ncol

lect

ible

Fac

tor

Ove

r(U

nder

) R

ecov

ery

Incl

. Int

eres

t($

72,6

13)

($35

,125

)($

4,54

3)($

28,9

18)

($77

9)($

2,63

1)($

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($2,

427)

($4,

855)

2.33

%($

12)

Feb

-19

($5,

911)

($2,

956)

($2,

956)

2.33

%($

9)($

765)

($38

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382)

2.33

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Mar

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($2,

964)

($2,

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2.33

%($

3)($

383)

($38

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2.33

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0)($

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Jan-

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67)

($76

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($1)

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88)

($

2,58

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(607

)

($

607)

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1)

Feb

-18

($76

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1)($

2,59

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2,59

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($4)

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2.33

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Apr

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($77

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($70

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($1)

($2,

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($21

7)($

2,38

4)2.

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($5)

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0)($

51)

($55

9)2.

33%

($1)

May

-18

($70

8)($

64)

($64

3)2.

33%

($1)

($2,

389)

($21

7)($

2,17

2)2.

33%

($4)

($56

0)($

51)

($50

9)2.

33%

($1)

Jun-

18($

645)

($64

)($

580)

2.33

%($

1)($

2,17

6)($

218)

($1,

958)

2.33

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4)($

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($51

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459)

2.33

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($58

1)($

65)

($51

7)2.

33%

($1)

($1,

962)

($21

8)($

1,74

4)2.

33%

($4)

($46

0)($

51)

($40

9)2.

33%

($1)

Aug

-18

($51

8)($

65)

($45

3)2.

33%

($1)

($1,

748)

($21

8)($

1,52

9)2.

33%

($3)

($41

0)($

51)

($35

9)2.

33%

($1)

Sep

-18

($45

4)($

65)

($38

9)2.

33%

($1)

($1,

533)

($21

9)($

1,31

4)2.

33%

($3)

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9)($

51)

($30

8)2.

33%

($1)

Oct

-18

($39

0)($

65)

($32

5)2.

33%

($1)

($1,

316)

($21

9)($

1,09

7)2.

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($2)

($30

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51)

($25

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($1)

Nov

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($32

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65)

($26

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($1)

($1,

099)

($22

0)($

879)

2.33

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2)($

258)

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206)

2.33

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0)D

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261)

($65

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196)

2.33

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0)($

881)

($22

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661)

2.33

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1)($

207)

($52

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155)

2.33

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($19

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65)

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($0)

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3)($

221)

($44

2)2.

33%

($1)

($15

5)($

52)

($10

4)2.

33%

($0)

Feb

-19

($13

1)($

66)

($66

)2.

33%

($0)

($44

3)($

221)

($22

1)2.

33%

($1)

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52)

($52

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33%

($0)

Mar

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($66

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66)

$02.

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($0)

($22

2)($

222)

$02.

33%

($0)

($52

)($

52)

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(c)

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(g)

(a)

(b)

(c)

(d)

(e)

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(g)

Jan-

16($

67,5

11)

($67

,511

)($

67,5

11)

2.54

%($

143)

($67

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2.54

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22)

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70)

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22)

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18)

($10

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59)

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66,0

39)

($10

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41)

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63)

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18)

($10

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33,3

84)

($18

1)($

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65)

($33

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14%

($60

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33,6

25)

May

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($66

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74)

2.14

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114)

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9,91

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33,6

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($32

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14%

($58

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31,7

97)

Jun-

16($

62,4

24)

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23)

($60

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14%

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7)($

57,7

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($9,

915)

$479

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($9,

676)

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17)

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454)

($31

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55)

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l-16

($57

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54,7

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98)

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29,6

39)

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75)

($28

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14%

($51

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27,2

26)

Aug

-16

($51

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)($

48,2

17)

2.14

%($

86)

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)($

8,92

9)$5

92($

8,33

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8,63

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8,35

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27,2

26)

$2,6

24($

24,6

02)

($25

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)2.

14%

($46

)($

24,6

48)

Sep

-16

($44

,646

)$6

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($38

,184

)($

41,4

15)

2.14

%($

74)

($38

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)($

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67)

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14%

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Oct

-16

($38

,258

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,759

)($

36,0

08)

2.14

%($

64)

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7,79

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($13

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7,34

8)($

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09)

$2,1

31($

19,9

78)

($21

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)2.

14%

($38

)($

20,0

16)

Nov

-16

($33

,823

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,697

)($

31,7

60)

2.14

%($

57)

($29

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14%

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6,94

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77)

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14%

($34

)($

18,1

11)

Dec

-16

($29

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($24

,985

)($

27,3

69)

2.14

%($

49)

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22)

($17

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14%

($31

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52)

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17($

25,0

33)

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19,5

73)

($22

,303

)2.

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($40

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13)

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241)

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11)

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992)

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992)

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484)

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10)

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494)

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23)

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64)

1.84

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19)

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942)

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494)

$494

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001)

($5,

248)

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8)($

5,00

9)($

12,0

10)

$2,0

74($

9,93

6)($

10,9

73)

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%($

17)

($9,

953)

(2)

Apr

-17

($9,

942)

$2,6

51($

7,29

1)($

8,61

6)1.

84%

($13

)($

7,30

4)($

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4,72

6)($

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84%

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($4,

733)

($9,

953)

$1,1

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8,78

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8)1.

84%

($14

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8,79

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(c)

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(f)

(g)

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(b)

(c)

(d)

(e)

(f)

(g)

Jan-

16($

34,1

10)

($34

,110

)($

34,1

10)

2.54

%($

72)

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)($

8,02

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)($

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3)($

1,06

6)($

1,06

6)($

1,06

6)2.

54%

($2)

($1,

068)

Feb

-16

($34

,182

)($

34,1

82)

($34

,182

)2.

54%

($72

)($

34,2

55)

($8,

043)

($8,

043)

($8,

043)

2.54

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17)

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060)

($1,

068)

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068)

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068)

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2)($

1,07

1)M

ar-1

6($

34,2

55)

($34

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)($

34,2

55)

2.14

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61)

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)($

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0)($

8,06

0)($

8,06

0)2.

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4)($

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1,07

1)($

1,07

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14%

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($1,

072)

(1)

Apr

-16

($34

,316

)($

145)

($34

,461

)($

34,3

88)

2.14

%($

61)

($34

,522

)($

8,07

4)$1

80($

7,89

4)($

7,98

4)2.

14%

($14

)($

7,90

8)($

1,07

2)($

5)($

1,07

7)($

1,07

5)2.

14%

($2)

($1,

079)

May

-16

($34

,522

)$1

,497

($33

,025

)($

33,7

73)

2.14

%($

60)

($33

,085

)($

7,90

8)$3

38($

7,57

0)($

7,73

9)2.

14%

($14

)($

7,58

4)($

1,07

9)$3

0($

1,04

9)($

1,06

4)2.

14%

($2)

($1,

051)

Jun-

16($

33,0

85)

$1,7

33($

31,3

52)

($32

,219

)2.

14%

($57

)($

31,4

10)

($7,

584)

$376

($7,

209)

($7,

396)

2.14

%($

13)

($7,

222)

($1,

051)

$28

($1,

023)

($1,

037)

2.14

%($

2)($

1,02

5)Ju

l-16

($31

,410

)$1

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($29

,655

)($

30,5

32)

2.14

%($

54)

($29

,709

)($

7,22

2)$3

90($

6,83

2)($

7,02

7)2.

14%

($13

)($

6,84

4)($

1,02

5)$3

0($

995)

($1,

010)

2.14

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2)($

997)

Aug

-16

($29

,709

)$1

,863

($27

,846

)($

28,7

78)

2.14

%($

51)

($27

,897

)($

6,84

4)$4

18($

6,42

6)($

6,63

5)2.

14%

($12

)($

6,43

7)($

997)

$30

($96

7)($

982)

2.14

%($

2)($

969)

Sep

-16

($27

,897

)$1

,893

($26

,005

)($

26,9

51)

2.14

%($

48)

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40)

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27)

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Jan-

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23)

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20)

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($7)

($3,

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($58

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Schedule ASC

-16




Schedule ASC-16

Calculation of Net Metering Charge

Total Renewable Generation

Credits

Energy Sales to ISO-NE for Net-

Metered Customers

Qualifying Facilities Power

Purchase Recoverable Costs Adjustment

Total Over(Under) Recovery

(a) (b) (c) (d) (e)

Jan-17 ($403,127) $9,013 ($85,951) $97,614 ($382,451)Feb-17 ($320,158) $12,073 ($82,208) ($390,293)Mar-17 ($523,729) $25,477 ($41,979) ($540,232)Apr-17 ($406,665) $9,365 ($36,410) ($29,564) ($463,274)

May-17 ($321,435) $9,098 ($34,398) ($346,735)Jun-17 ($235,914) $41,227 ($48,177) ($242,864)Jul-17 ($263,590) $447,218 ($34,692) $148,936

Aug-17 ($181,674) $76,746 ($10,035) ($114,963)Sep-17 ($252,343) $104,448 ($191) ($148,085)Oct-17 ($291,853) $46,631 ($3,859) ($249,081)

Nov-17 ($354,508) $65,070 ($38,687) ($328,125)Dec-17 ($378,957) $295,815 ($9,204) ($92,346)

($3,933,952) $1,142,180 ($425,790) $68,049 ($3,149,512)

(1) Forecasted kWhs April 1, 2018 through March 31, 2019 7,292,662,088

(2) Proposed Net Metering Charge $0.00043

(a) per company reports(b) from ISO monthly bill(c) per invoices(d)

(e) Col (a) + Col (b) + Col (c) + Col (d)

(1) per company forecast(2) Total Over(Under) Recovery per column (e) ÷ forecasted kWhs, truncated to 5 decimal places

Calculation of Net Metering Charge

Through the Period Ending December 31, 2017

January 2017; Cumulative Net Metering Energy Sale Resettlement Corrections, incl. interest. April 2017 Page 3, Remaining Balance from Over(Under) Recovery incurred during 2015


Net Metering Reconciliation


Beginning Over (Under) Recovery

BalanceNet Metering

RevenueEnding Over (Under)

Recovery Balance(a) (b) (c)

Jan-17 ($1,713,779) ($1,713,779)Feb-17 ($1,713,779) ($1,713,779)Mar-17 ($1,713,779) ($1,713,779)

(1) Apr-17 ($1,713,779) $56,517 ($1,657,262)May-17 ($1,657,262) $119,452 ($1,537,810)Jun-17 ($1,537,810) $136,294 ($1,401,516)Jul-17 ($1,401,516) $162,358 ($1,239,158)

Aug-17 ($1,239,158) $163,734 ($1,075,424)Sep-17 ($1,075,424) $148,311 ($927,113)Oct-17 ($927,113) $134,323 ($792,789)

Nov-17 ($792,789) $130,602 ($662,187)Dec-17 ($662,187) $131,354 ($530,832)Jan-18 ($530,832) $162,800 ($368,032)Feb-18 ($368,032) $0 ($368,032)Mar-18 ($368,032) $0 ($368,032)

(2) Apr-18 ($368,032) $0 ($368,032)

Totals ($1,713,779) $1,345,748 ($368,032)

(1) reflects revenues based on kWhs consumed prior to April 1(2) reflects revenues based on kWhs consumed after April 1

(a)

(b) per company reports(c) column (a) + column (b)

from previous month column (c); beginning balance per RIPUC Docket No. 4691 filed February 2017, Schedule ASC-16, page 1


Net Metering Reconciliation


Beginning Over (Under) Recovery

BalanceNet Metering

RevenueEnding Over (Under)

Recovery Balance(a) (b) (c)

Jan-16 ($551,915) ($551,915)Feb-16 ($551,915) ($551,915)Mar-16 ($551,915) ($551,915)

(1) Apr-16 ($551,915) $18,201 ($533,714)May-16 ($533,714) $35,470 ($498,244)Jun-16 ($498,244) $42,788 ($455,456)Jul-16 ($455,456) $48,407 ($407,049)

Aug-16 ($407,049) $55,035 ($352,014)Sep-16 ($352,014) $52,015 ($300,000)Oct-16 ($300,000) $40,879 ($259,121)

Nov-16 ($259,121) $37,724 ($221,397)Dec-16 ($221,397) $40,832 ($180,565)Jan-17 ($180,565) $44,749 ($135,816)Feb-17 ($135,816) $41,928 ($93,888)Mar-17 ($93,888) $40,927 ($52,960)

(2) Apr-17 ($52,960) $23,396 ($29,564)

Totals ($551,915) $522,351 ($29,564)

(1) reflects revenues based on kWhs consumed prior to April 1(2) reflects revenues based on kWhs consumed after April 1

(a)

(b) per company reports(c) column (a) + column (b)

from previous month column (c); beginning balance per RIPUC Docket No. 4599 filed February 2016, Schedule ASC-16, page 1


Schedule ASC

-17




Schedule ASC-17

Net Metering Report for 2017

Facility ID Town Capacity (kW) Fuel Type DG typeDate Authority to Interconnect

SentRate Class

Estimated Annual

Generation - kWh

RI-000090 Pawtucket 0.5 Solar Inverter 7/31/1998 A-16 550

RI-000083 East Greenwich 1 Solar Inverter 9/3/1998 A-16 1,100

NECO-000026 Charlestown 2.1 Solar Inverter 7/22/1999 A-16 2,310

RI-000116 Middletown 58 Solar Inverter 9/9/1999 G-32 63,800

RI-000084 Foster 4 Solar Inverter 12/31/1999 A-16 4,400

RI-000085 WARWICK 1.4 Solar Inverter 6/15/2000 A-16 1,540

RI-000086 Cranston 0.3 Solar Inverter 7/1/2000 A-16 330

RI-000088 Portsmouth 5 Solar Inverter 10/1/2000 A-16 5,500

NECO-000035 Providence 1.14 Solar Inverter 6/21/2001 A-16 1,254

NECO-000036 Middletown 1.8 Solar Inverter 11/1/2001 A-16 1,980

NECO-000037 Burrillville 2 Solar Inverter 1/1/2002 G-32 2,200

NECO-000034 West Kingston 5.76 Solar Inverter 3/12/2002 G-02 6,336

NECO-000033 Providence 2 Solar Inverter 5/1/2002 G-32 2,200

NECO-000031 Cranston 2 Solar Inverter 8/15/2002 G-32 2,200

NECO-000032 North Kingstown 2 Solar Inverter 8/15/2002 G-02 2,200

NECO-000030 West Kingston 2.5 Solar Inverter 2/3/2003 A-16 2,750

NECO-000003 Charlestown 3.6 Solar Inverter 8/1/2003 A-16 3,960

NECO-000002 Wakefield 10 Wind (blank) 8/4/2003 A-16 24,000

NECO-000004 Cranston 3 Solar Inverter 10/6/2003 A-16 3,300

NECO-000006 Westerly 3 Solar Inverter 1/15/2004 A-16 3,300

NECO-000007 Bristol 8 Solar Inverter 5/14/2004 G-02 8,800

NECO-000014 Cumberland 8.4 Solar Inverter 9/10/2004 A-16 9,240

NECO-000024 Bristol 3.6 Solar Inverter 9/17/2004 G-32 3,960

NECO-000025 Bristol 9 Solar Inverter 9/17/2004 G-32 9,900

NECO-000001 Little Compton 10.53 Solar Inverter 10/27/2004 A-16 11,583

NECO-000008 Westerly 5 Solar Inverter 10/28/2004 A-16 5,500

NECO-000023 Narragansett 5.3 Solar Inverter 11/9/2004 A-16 5,830

RI-000004 Charlestown 2.7 Solar Inverter 1/7/2005 A-16 2,970

NECO-000009 West Greenwich 1.8 Solar Inverter 3/9/2005 G-02 1,980

NECO-000018 SCITUATE 1.8 Solar Inverter 5/5/2005 G-32 1,980

NECO-000010 Providence 20.04 Solar Inverter 5/10/2005 G-02 22,044

RI-000001 Little Compton 10.03 Solar Inverter 5/25/2005 A-16 11,033

NECO-000027 Providence 3.96 Solar Inverter 5/27/2005 A-16 4,356

RI-000087 North Kingstown 3 Solar Inverter 6/1/2005 A-16 3,300

NECO-000022 Wood River Jct 15 Solar Inverter 6/2/2005 C-06 16,500

NECO-000011 WARWICK 8.95 Solar Inverter 6/21/2005 A-16 9,845

NECO-000015 Barrington 4.488 Solar Inverter 8/10/2005 A-16 4,937

NECO-000021 Barrington 2.9 Solar Inverter 8/12/2005 A-16 3,190

NECO-000020 WARWICK 7.3 Solar Inverter 8/12/2005 A-16 8,030

NECO-000016 Tiverton 5.1 Solar Inverter 8/24/2005 A-16 5,610

NECO-000017 Lincoln 5.1 Solar Inverter 8/24/2005 A-16 5,610

RI-000007 Providence 1 Solar Inverter 10/25/2005 G-62 1,100

RI-000045 Narragansett 4 Solar Inverter 10/27/2005 A-16 4,400

RI-000010 Tiverton 5 Solar Inverter 10/27/2005 G-02 5,500

RI-000006 Cumberland 3.05 Solar Inverter 12/12/2005 A-16 3,355

NECO-000028 Providence 24.9 Solar Inverter 12/29/2005 G-32 27,390

The Narragansett Electric CompanyNET METERING REPORT



SentRate Class

Estimated Annual

Generation - kWh

RI-000069 West Kingston 5.55 Solar Inverter 12/31/2005 A-16 6,105

RI-000044 Middletown 3 Solar Inverter 1/1/2006 C-06 3,300


RI-000041 Providence 1.1 Solar Inverter 1/26/2006 C-06 1,210

RI-000027 Providence 6 Solar Inverter 1/27/2006 A-16 6,600

RI-000033 Ashaway 6.84 Solar Inverter 1/27/2006 A-16 7,524

RI-000038 Providence 3.42 Solar Inverter 2/7/2006 A-16 3,762



NECO-000013 Wakefield 5.32 Solar Inverter 3/17/2006 A-16 5,852

RI-000012 Kingstown 5.86 Solar Inverter 3/31/2006 C-06 6,446

NECO-000019 Portsmouth 660 Wind Induction 4/1/2006 G-32 1,584,000

RI-000011 Charlestown 4 Solar Inverter 4/7/2006 A-16 4,400

RI-000032 GLOUCESTER 4.56 Solar Inverter 4/14/2006 A-16 5,016

RI-000008 Smithfield 10.54 Solar Inverter 4/14/2006 A-16 11,594

RI-000014 Tiverton 4.008 Solar Inverter 4/17/2006 A-16 4,409

RI-000026 West Kingston 4 Solar Inverter 4/27/2006 A-16 4,400


NECO-000029 Cranston 50 Solar Inverter 5/1/2006 C-06 55,000

RI-000039 Warren 4.56 Solar Inverter 5/9/2006 A-16 5,016

RI-000016 Wakefield 5.7 Solar Inverter 5/9/2006 A-16 6,270

RI-000022 Westerly 3.99 Solar Inverter 5/18/2006 A-16 4,389

RI-000003 Peacedale 5.1 Solar Inverter 6/2/2006 A-16 5,610

RI-000025 Portsmouth 3.4 Solar Inverter 7/5/2006 A-16 3,740

RI-000019 Narragansett 3.3 Solar Inverter 7/26/2006 A-16 3,630

RI-000021 South Kingstown 3.8 Solar Inverter 7/26/2006 A-16 4,180




RI-000054 Portsmouth 1.8 Solar Inverter 8/31/2006 G-02 1,980




RI-000013 Hope Valley 6.88 Solar Inverter 10/30/2006 A-16 7,568

RI-000036 Jamestown 1.4 Solar Inverter 11/2/2006 A-16 1,540

RI-000051 Bristol 4.2 Solar Inverter 12/1/2006 A-16 4,620


RI-000018 Barrington 3.25 Solar Inverter 12/19/2006 A-16 3,575

RI-000009 Bristol 4 Solar Inverter 12/19/2006 A-16 4,400

RI-000042a Westerly 5.9 Solar Inverter 1/11/2007 A-16 6,490

RI-000042b Westerly 5.9 Solar Inverter 1/11/2007 A-16 6,490



RI-000049 Bristol 2 Solar Inverter 1/31/2007 G-02 2,200

RI-000050 Middletown 2 Solar Inverter 2/1/2007 G-02 2,200

RI-000043 Pawtucket 3.4 Solar Inverter 2/2/2007 A-16 3,740



SentRate Class

Estimated Annual

Generation - kWh


RI-000037 Cranston 5.7 Solar Inverter 2/16/2007 A-16 6,270

RI-000053 SCITUATE 15.45 Solar Inverter 6/11/2007 C-06 16,995

RI-000059 North Smithfield 2 Solar Inverter 7/6/2007 G-32 2,200

RI-000060 Covertry 2 Solar Inverter 7/6/2007 G-32 2,200

RI-000062 Hope Valley 3.12 Solar Inverter 7/19/2007 C-06 3,432



RI-000056 Greenville 19.4 Solar Inverter 9/26/2007 G-02 21,340

RI-000061 Peace Dale 2 Solar Inverter 9/27/2007 G-32 2,200

RI-000074 WARWICK 1.75 Solar Inverter 10/1/2007 A-16 1,925

RI-000072 Middletown 2.45 Solar Inverter 10/12/2007 A-16 2,695


RI-000080 Wakefield 2.4 Wind Inverter 10/23/2007 A-16 5,760

RI-000078 SCITUATE 7.56 Solar Inverter 10/29/2007 A-16 8,316


RI-000079 Newport 24.5 Solar Inverter 11/16/2007 G-02 26,950


RI-000058 West Greenwich 1.575 Solar Inverter 12/13/2007 C-06 1,733


RI-000055 Wakefield 7 Solar Inverter 12/31/2007 A-16 7,700


RI-000102 West Warwick 2 Solar Inverter 6/13/2008 G-02 2,200




RI-000100 Middletown 4.8 Wind (blank) 7/3/2008 A-16 11,520


RI-000103 Saunderstown 3 Solar Inverter 9/17/2008 A-16 3,300

RI-000112 Portsmouth 3 Solar Inverter 9/26/2008 A-16 3,300



RI-000111 Providence 3.28 Solar Inverter 10/8/2008 C-06 3,608

RI-000113 Newport 3.07 Solar Inverter 10/14/2008 A-16 3,377


RI-000120 Middletown 1.2 Wind Inverter 11/20/2008 A-16 2,880

RI-000119 Middletown 1.98 Solar Inverter 11/20/2008 A-16 2,178

RI-000117 Newport 2 Solar Inverter 11/20/2008 A-16 2,200

RI-000121 Johnston 2.88 Solar Inverter 12/8/2008 A-16 3,168


RI-000122 Tiverton 2 Solar Inverter 1/14/2009 A-16 2,200

RI-000128 North Providence 3.15 Solar Inverter 1/15/2009 A-16 3,465

RI-000124 W. Greenwich 5.04 Solar Inverter 1/15/2009 A-16 5,544

RI-000123 Middletown 27.6 Solar Inverter 2/17/2009 C-06 30,360

RI-000129 Hope (Fiskeville) 6 Solar Inverter 2/26/2009 A-16 6,600

RI-000101 Portsmouth 1500 Wind Induction 3/18/2009 G-32 3,600,000



SentRate Class

Estimated Annual

Generation - kWh

RI-000135 Wyoming 7 Solar Inverter 4/1/2009 A-16 7,700


RI-000137 Johnston 5.46 Solar Inverter 4/22/2009 A-16 6,006

RI-000108 WARWICK 23.625 Solar Inverter 5/18/2009 G-02 25,988

RI-000136 Hopkinton 1.8 Solar Inverter 6/19/2009 A-16 1,980

RI-000144 Foster 1.3 Wind Inverter 7/6/2009 A-16 3,120

RI-000142 Charleston 4.2 Solar Inverter 7/7/2009 A-16 4,620

RI-000132 WARWICK 100 Wind Inverter 8/18/2009 G-32 240,000

RI-000147 Cranston 3.85 Solar Inverter 8/20/2009 A-16 4,235


RI-000148 Prudence Island 2.1 Solar Inverter 11/19/2009 A-16 2,310

RI-000157 Hope Valley 3.6 Solar Inverter 12/4/2009 A-16 3,960

RI-000146 Middletown 100 Wind Inverter 12/10/2009 G-02 240,000



RI-000159 Cumberland 5 Solar Inverter 1/11/2010 A-16 5,500

RI-000163 Woonsocket 3 Solar Inverter 1/12/2010 A-16 3,300


RI-000152 Tiverton 4.8 Solar Inverter 2/22/2010 A-16 5,280

RI-000176 N Smithfield 1.5 Wind Inverter 6/10/2010 A-16 3,600

RI-000177 Barrington 6 Solar Inverter 6/22/2010 A-16 6,600

RI-000174 Rumford 3 Solar Inverter 7/19/2010 A-16 3,300

RI-000183 Little Compton 3 Solar Inverter 7/19/2010 A-16 3,300

RI-000184 Bristol 4 Solar Inverter 7/23/2010 A-16 4,400

RI-000172 SCITUATE 4 Solar Inverter 7/26/2010 A-16 4,400

RI-000175 Providence 1.5 Wind Inverter 8/2/2010 C-06 3,600

RI-000156 South Kingston(Wakefield) 3.15 Solar Inverter 8/17/2010 A-16 3,465


RI-000127 Narragansett 10 Wind Inverter 10/8/2010 C-06 24,000

RI-000178 Little Compton 14 Solar Inverter 10/19/2010 A-16 15,400

RI-000194 Exeter 3.61 Solar Inverter 11/10/2010 A-16 3,971

RI-000190 Jamestown 4 Solar Inverter 11/16/2010 C-02 4,400

RI-000170 Barrington 3 Solar Inverter 11/19/2010 A-16 3,300

RI-000181 SCITUATE 3 Solar Inverter 11/19/2010 A-16 3,300

13244665 Newport 1.2 Wind Other 2/1/2010 G-62 2,880

13244823 Newport 7 Wind Other 2/1/2010 G-62 16,800

13244440 Hope Valley 6 Solar Inverter 2/12/2010 A-16 6,600

13244999 Foster 5.3 Solar Inverter 2/26/2010 A-16 5,830

13338797 EAST GREENWICH 50 Solar Inverter 6/7/2011 G-32 55,000

13335868 PROVIDENCE 7 Solar Inverter 8/5/2011 C-06 7,700

RI-000209 North Kingstown 1.5 Wind Inverter 1/7/2011 A-16 3,600

RI-000207 West Kingston 4 Solar Inverter 1/13/2011 A-16 4,400




RI-000188 Pawtucket 164 Solar Inverter 3/2/2011 G-32 180,400

RI-000192a Johnston 19 Solar Inverter 3/9/2011 G-02 20,900

RI-000212 South Kingston 2.6 Solar Inverter 3/18/2011 A-16 2,860

RI-000201 Charlestown 30 Solar Inverter 3/22/2011 G-02 33,000

RI-000200 North Kingston 2.9 Solar Inverter 3/23/2011 A-16 3,190

RI-000191 Providence 50 Solar Inverter 3/23/2011 C-02 55,000

RI-000192c Providence 20.3 Solar Inverter 3/30/2011 G-02 22,330

RI-000192b Barrington 21 Solar Inverter 4/5/2011 G-02 23,100

RI-000218 Compton 4.8 Solar Inverter 4/8/2011 A-16 5,280

RI-000210 Newport 1.14 Solar Inverter 7/13/2011 A-16 1,254



SentRate Class

Estimated Annual

Generation - kWh


RI-000228 North Smithfield 13 Solar Inverter 8/11/2011 G-32 14,300


RI-000235 Providence 4 Solar Inverter 10/10/2011 A-16 4,400

RI-000227 Lincoln 60 Solar Inverter 10/10/2011 G-02 66,000

RI-000230 Littlecompton 4 Solar Inverter 10/17/2011 A-16 4,400

RI-000213 Narragansett 100 Wind Inverter 10/19/2011 G-02 240,000



RI-000234 Hope Valley 6 Solar Inverter 12/20/2011 A-16 6,600

13433708 L COMPTON 4 Solar Inverter 1/20/2012 A-16 4,400

13163366 CRANSTON 3 Solar Inverter 1/27/2012 A-16 3,300

13163630 KENYON 4 Solar Inverter 1/27/2012 A-16 4,400

13287157 WEST WARWICK 150 Solar Inverter 1/27/2012 G-02 165,000

13168640 TIVERTON 5 Solar Inverter 1/30/2012 A-16 5,500

13337931 WEST WARWICK 225 Hydro Synchronous 2/1/2012 B-32 450,000

13286055 CUMBERLAND 260 Solar Inverter 2/10/2012 G-32 286,000

12240150 BRISTOL 4 Solar Inverter 2/13/2012 A-16 4,400

13163682 ESMOND 7 Solar Inverter 2/13/2012 A-16 7,700

13169212 PROVIDENCE 0.57 Solar Inverter 2/13/2012 A-16 627

12148883 NEWPORT 8 Solar Inverter 2/28/2012 A-16 8,800

13168408 RUMFORD 4 Solar Inverter 2/29/2012 A-16 4,400


13168551 LINCOLN 5 Solar Inverter 3/9/2012 A-16 5,500

13551480 LINCOLN 6 Solar Inverter 3/12/2012 G-02 6,600

13170555 PEACE DALE 7.2 Solar Inverter 3/14/2012 A-16 7,920

12381648 L COMPTON 7.5 Solar Inverter 3/16/2012 C-06 8,250

13168708 PRUDENCE ISL 3 Solar Inverter 3/16/2012 C-02 3,300

13169065 NARRAGANSETT 10 Solar Inverter 3/30/2012 G-02 11,000

13168803 NORTH KINGSTOWN 20 Solar Inverter 4/2/2012 G-02 22,000

12729266 WOOD RIVER JT 6 solar Inverter 5/1/2012 A-16 6,600

12808914 PAWTUCKET 23 Solar Inverter 5/10/2012 G-02 25,300

13433977 BRISTOL 50 Wind (blank) 5/14/2012 C-02 120,000

13177748 JOHNSTON 6 Solar Inverter 5/22/2012 C-06 6,600

12778215 PROVIDENCE 4.73 solar Inverter 5/30/2012 A-16 5,203

12723949 PROVIDENCE 3 solar Inverter 5/31/2012 A-16 3,300


12797813 PROVIDENCE 4.73 solar Inverter 5/31/2012 c-06 5,203

13168581 JAMESTOWN 4 Solar Inverter 6/25/2012 C-06 4,400

13168917 WESTERLY 10 Solar Inverter 6/25/2012 C-02 11,000


12981846 PROVIDENCE 3.44 Solar Inverter 7/2/2012 A-16 3,784

12930973 NORTH KINGSTOWN 2 solar Inverter 7/16/2012 A-16 2,200


12700487 PROVIDENCE 1.29 solar Inverter 7/19/2012 C-06 1,419

13262387 NARRAGANSETT 3.66 Solar Inverter 7/20/2012 A-16 4,026

13086985 PROVIDENCE 4.73 Solar Inverter 7/30/2012 C-06 5,203





SentRate Class

Estimated Annual

Generation - kWh



12700157 PROVIDENCE 6.45 solar Inverter 8/29/2012 C-06 7,095

13356318 SAUNDERSTOWN 2.37 Solar Inverter 9/4/2012 A-16 2,607



12613705 PROVIDENCE 50 solar Inverter 9/18/2012 G-62 55,000

13256165 WAKEFIELD 4.95 Solar Inverter 9/28/2012 A-16 5,445

13609645 L COMPTON 1.72 Solar Inverter 9/28/2012 A-16 1,892


13188008 CRANSTON 21 Solar Inverter 10/10/2012 G-02 23,100

13755485 CHARLESTOWN 7 Solar Inverter 11/16/2012 A-16 7,700

13679422 JAMESTOWN 1.29 Solar Inverter 11/20/2012 A-16 1,419

13868654 BARRINGTON 3.87 Solar Inverter 11/26/2012 A-16 4,257

13301833 NORTH SMITHFIELD 5.3 Solar Inverter 11/30/2012 A-16 5,830

13854152 WESTERLY 5 Solar Inverter 12/5/2012 A-16 5,500

12762756 CRANSTON 3.65 Solar Inverter 12/20/2012 A-16 4,015

12282568 BRADFORD 10.3 Solar Inverter 12/21/2012 G-32 11,330

13605369 CUMBERLAND 0.43 Solar Inverter 2/6/2013 C-06 473

13605566 PROVIDENCE 0.43 Solar Inverter 2/6/2013 C-06 473


13933429 JAMESTOWN 4 Solar Inverter 2/22/2013 A-16 4,400

14588725 EAST GREENWICH 1.51 Solar Inverter 3/26/2013 A-16 1,661


14726048 EAST GREENWICH 4 Solar Inverter 5/3/2013 A-16 4,400


14847417 NARRAGANSETT 4 Solar Inverter 6/14/2013 A-16 4,400

14278306 PROVIDENCE 0.86 Solar Inverter 6/26/2013 A-16 946


14129872 WEST WARWICK 12.9 Solar Inverter 7/3/2013 C-06 14,190

14726475 NEWPORT 2.15 Solar Inverter 7/10/2013 A-16 2,365


14601995 NORTH SCITUATE 5.16 Solar Inverter 7/19/2013 A-16 5,676

14589949 BRISTOL 28 Solar Inverter 7/31/2013 G-02 30,800

14790269 NORTH KINGSTOWN 23 Solar Inverter 8/2/2013 G-02 25,300

14601876 FOSTER 2.15 Solar Inverter 8/8/2013 A-16 2,365

14276693 MIDDLETOWN 0.86 Solar Inverter 8/9/2013 A-16 946


14761875 MIDDLETOWN 3.66 Solar Inverter 8/9/2013 A-16 4,026


13220170 PROVIDENCE 300 Solar Inverter 8/14/2013 G-32 330,000

13425175 MIDDLETOWN 20 Solar Inverter 8/16/2013 A-16 22,000

14767040 PROVIDENCE 4 Solar Inverter 8/16/2013 A-16 4,400

15481450 JOHNSTON 10 Solar Inverter 8/20/2013 c-06 11,000


15476331 PORTSMOUTH 2.5 Solar Inverter 8/22/2013 A-16 2,750


15280721 CHEPACHET 6.02 Solar Inverter 9/4/2013 A-16 6,622


15358807 CHARLESTOWN 5.16 Solar Inverter 9/4/2013 A-16 5,676



SentRate Class

Estimated Annual

Generation - kWh


14753836 EXETER 5.16 Solar Inverter 9/19/2013 A-16 5,676


15289861 TIVERTON 4.3 Solar Inverter 9/19/2013 A-16 4,730



15128281 WESTERLY 7.96 Solar Inverter 10/3/2013 A-16 8,756



15140057 WARREN 3.66 Solar Inverter 10/16/2013 A-16 4,026


15551310 JOHNSTON 4.09 Solar Inverter 10/16/2013 A-16 4,499






15960523 HOPE 3.87 Solar Inverter 10/29/2013 C-06 4,257

15613973 WARWICK 3.6 Solar Inverter 11/6/2013 A-16 3,960


16020398 PAWTUCKET 5.16 Solar Inverter 11/18/2013 A-16 5,676



15950635 NEWPORT 5.16 Solar Inverter 11/26/2013 C-06 5,676







13105351 RUMFORD 45.6 Solar Inverter 12/20/2013 c-06 50,160

13252180 PAWTUCKET 1.64 solar Inverter 8/9/2009 A-16 1,804 12440329 WARWICK 19.5 solar Inverter 6/13/2011 C-06 21,450

RI-000199 North Kingstown 405 Solar Inverter 9/9/2011 B-62 445,500 13339553 PORTSMOUTH 225 Wind Inverter 3/20/2012 G-02 540,000 13511760 TIVERTON 275 Wind Inverter 6/5/2012 C-06 660,000 12364353 EXETER 15.3 solar Inverter 6/19/2012 C-06 16,830 13115934 PROVIDENCE 4500 Wind Inverter 10/16/2012 G-32 10,800,000 12252717 NARRAGANSETT 10 Wind Inverter 12/4/2012 G-02 24,000 15779010 NORTH SCITUATE 10.75 Solar Inverter 1/10/2014 A-16 11,825 15660814 JAMESTOWN 7.65 Solar Inverter 1/14/2014 A-16 8,415 16119917 JAMESTOWN 5 Solar Inverter 1/14/2014 A-16 5,500 16281029 BARRINGTON 3.44 Solar Inverter 1/14/2014 A-16 3,784 15680716 JAMESTOWN 6.45 Solar Inverter 1/17/2014 A-16 7,095 15987219 PROVIDENCE 3.44 Solar Inverter 1/28/2014 A-16 3,784 15551662 PROVIDENCE 3.44 Solar Inverter 1/28/2014 A-16 3,784 15650232 PROVIDENCE 3.87 Solar Inverter 1/28/2014 A-16 4,257 16049358 PROVIDENCE 4.3 Solar Inverter 1/28/2014 A-16 4,730 16052781 PROVIDENCE 3.01 Solar Inverter 1/28/2014 A-16 3,311 16240969 PROVIDENCE 3.87 Solar Inverter 1/28/2014 A-16 4,257 14797804 FOSTER 8 Solar Inverter 1/29/2014 A-16 8,800 16020824 WARREN 1.29 Solar Inverter 2/3/2014 A-16 1,419



SentRate Class

Estimated Annual

Generation - kWh

15862797 L COMPTON 4 Solar Inverter 2/11/2014 A-16 4,400 16315480 WAKEFIELD 6 Solar Inverter 2/11/2014 A-16 6,600 15700681 JAMESTOWN 2.58 Solar Inverter 3/5/2014 A-16 2,838 16538805 WESTERLY 5 Solar Inverter 4/11/2014 A-16 5,500


16863933 WEST WARWICK 0.43 Solar Inverter 5/1/2014 A-16 473




13177831 WARREN 0.57 Solar Inverter 5/23/2014 A-16 627


15672618 PAWTUCKET 24 Solar Inverter 6/5/2014 g-62 26,400







16789421 PORTSMOUTH 5 Solar Inverter 7/2/2014 A-16 5,500



15430757 WAKEFIELD 3 Solar Inverter 7/16/2014 A-16 3,300



17099078 PAWTUCKET 3 Solar Inverter 8/4/2014 A-16 3,300

16617414 MIDDLETOWN 60 Solar Inverter 8/18/2014 c-06 66,000


16841481 RUMFORD 5.25 Solar Inverter 8/21/2014 A-16 5,775




17584869 WEST KINGSTON 4 Solar Inverter 8/27/2014 A-16 4,400

16611202 EAST PROVIDENCE 75 Solar Inverter 9/3/2014 C-06 82,500





16631931 WARWICK 30 Solar Inverter 9/9/2014 G-02 33,000

17447224 LINCOLN 3.44 Solar Inverter 9/26/2014 A-16 3,784


17449362 HOPE 7.6 Solar Inverter 9/29/2014 A-16 8,360


17665432 NORTH KINGSTOWN 2.5 Solar Inverter 10/1/2014 A-16 2,750





17471891 GREENVILLE 3.87 Solar Inverter 10/14/2014 A-16 4,257



17891429 EXETER 2 Solar Inverter 10/23/2014 A-16 2,200



17413565 RIVERSIDE 3.5 Solar Inverter 10/29/2014 A-16 3,850





SentRate Class

Estimated Annual

Generation - kWh





18154533 WOOD RIVER JT 3.5 Solar Inverter 11/10/2014 A-16 3,850

17281317 NORTH KINGSTOWN 9 Solar Inverter 11/13/2014 C-06 9,900

17513659 CUMBERLAND 4.5 Solar Inverter 11/14/2014 A-16 4,950





17832890 JOHNSTON 5 Solar Inverter 11/24/2014 A-16 5,500




17473280 BRISTOL 6.5 Solar Inverter 12/10/2014 A-16 7,150




17766993 WEST KINGSTON 14.25 Solar Inverter 12/22/2014 A-16 15,675




18416675 PEACE DALE 6 Solar Inverter 12/30/2014 A-16 6,600


13169627 COVENTRY 100 Solar Inverter 2/27/2012 G-02 110,000


18187567 BARRINGTON 5 Solar Inverter 1/2/2015 A-16 5,500



17505949 WARREN 8 Solar Inverter 1/16/2015 A-16 8,800



17283959 NORTH SMITHFIELD 185.6 Solar Inverter 1/30/2015 G-02 204,160

18772378 BURRILLVILLE 45 Solar Inverter 2/3/2015 G-32 49,500

17722568 WOONSOCKET 9.46 Solar Inverter 2/5/2015 G-02 10,406



17987568 COVENTRY 5 Solar Inverter 2/12/2015 A-16 5,500



18754877 HOPKINTON 9 Solar Inverter 2/26/2015 A-16 9,900








18989989 NORTH KINGSTOWN 3 Solar Inverter 3/25/2015 A-16 3,300










SentRate Class

Estimated Annual

Generation - kWh






18366178 WEST GREENWICH 4.2 Solar Inverter 4/30/2015 A-16 4,620

18960165 BURRILLVILLE 4.5 Solar Inverter 4/30/2015 A-16 4,950




17344217 NORTH KINGSTOWN 10 Solar Inverter 5/7/2015 C-06 11,000


18721804 GREENE 8.75 Solar Inverter 5/7/2015 A-16 9,625

18348135 SAUNDERSTOWN 6 Solar Inverter 5/13/2015 A-16 6,600




18936614 CUMBERLAND 5 Solar Inverter 5/19/2015 A-16 5,500






18856922 SLATERSVILLE 3.25 Solar Inverter 6/1/2015 A-16 3,575

18365562 WYOMING 14.25 Solar Inverter 6/3/2015 A-16 15,675


19017395 BRADFORD 3.8 Solar Inverter 6/4/2015 A-16 4,180



18494358 WEST WARWICK 6.75 Solar Inverter 6/8/2015 A-16 7,425

18619674 WEST GREENWICH 9.75 Solar Inverter 6/8/2015 C-06 10,725



19550488 TIVERTON 5 Solar Inverter 6/8/2015 C-06 5,500




18559630 NORTH SMITHFIELD 4 Solar Inverter 6/11/2015 A-16 4,400











15613020 NEWPORT 17.28 Solar Inverter 6/29/2015 c-06 19,008






18348360 HOPE VALLEY 5.5 Solar Inverter 7/6/2015 A-16 6,050




SentRate Class

Estimated Annual

Generation - kWh







18401763 WEST GREENWICH 8 Solar Inverter 7/15/2015 A-16 8,800














16632724 PROVIDENCE 56 Solar Inverter 7/27/2015 c-06 61,600





18494462 FORESTDALE 5.75 Solar Inverter 7/30/2015 A-16 6,325




19017394 FORESTDALE 6.25 Solar Inverter 7/31/2015 A-16 6,875















18360154 MIDDLETOWN 63 Solar Inverter 8/20/2015 C-06 69,300














SentRate Class

Estimated Annual

Generation - kWh


19876998 WARWICK 5 Solar Inverter 8/31/2015 A-16 5,500





19876697 WOONSOCKET 6 Solar Inverter 9/3/2015 A-16 6,600




19016256 NORTH PROVIDENCE 2.5 Solar Inverter 9/10/2015 A-16 2,750

19669607 NARRAGANSETT 44.5 Solar Inverter 9/11/2015 C-06 48,950








19691732 PROVIDENCE 44.5 Solar Inverter 9/18/2015 G-02 48,950

20117502 NORTH PROVIDENCE 10 Solar Inverter 9/18/2015 A-16 11,000









19058173 COVENTRY 4.5 Solar Inverter 10/1/2015 A-16 4,950








19058488 SMITHFIELD 7.25 Solar Inverter 10/8/2015 A-60 7,975






19701843 WEST WARWICK 3 Solar Inverter 10/14/2015 A-16 3,300















SentRate Class

Estimated Annual

Generation - kWh

20126958 KINGSTON 3.8 Solar Inverter 10/20/2015 A-16 4,180


19687957 CENTRAL FALLS 0.43 Solar Inverter 10/21/2015 C-06 473




19552116 SLATERSVILLE 8 Solar Inverter 10/21/2015 A-16 8,800





20196659 HOPE VALLEY 5 Solar Inverter 10/27/2015 C-06 5,500



19815323 MIDDLETOWN 18 Solar Inverter 10/28/2015 C-06 19,800





19633116 ADAMSVILLE 7.6 Solar Inverter 10/29/2015 A-16 8,360








19458228 NEWPORT 9 Solar Inverter 10/30/2015 G-02 9,900














20210073 WOONSOCKET 3.8 Solar Inverter 11/6/2015 A-16 4,180




17453649 WEST WARWICK 26 Solar Inverter 11/16/2015 c-06 28,600













SentRate Class

Estimated Annual

Generation - kWh

20110557 GLOCESTER 4.3 Solar Inverter 11/20/2015 A-16 4,730






























20858456 TIVERTON 7.6 Solar Inverter 12/14/2015 C-06 8,360




























SentRate Class

Estimated Annual

Generation - kWh











19735822 EAST PROVIDENCE 3.8 Solar Inverter 12/23/2015 A-16 4,180










20148654 RIVERSIDE 44 Solar Inverter 12/24/2015 G-32 48,400






20429297 RIVERSIDE 5 Solar Inverter 12/30/2015 A-16 5,500


20593600 WEEKAPAUG 7.6 Solar Inverter 12/30/2015 A-16 8,360



14319785 COVENTRY 1500 Wind Inverter 10/13/2016 G-32 3,600,000

14462941 COVENTRY 4500 Wind Inverter 8/5/2016 G-32 10,800,000


18803453 EAST PROVIDENCE 264 Solar Inverter 5/23/2016 G-02 290,400



19307209 LINCOLN 39.9 Solar Inverter 8/18/2016 G-02 43,890

19403715 NORTH SMITHFIELD 20 Solar Inverter 3/16/2016 C-06 22,000

19539750 WEST WARWICK 384 Solar Inverter 10/10/2016 C-06 422,400

19721699 CLAYVILLE 5 Solar Inverter 1/6/2016 A-16 5,500

19732103 WEST WARWICK 375 Solar Inverter 12/30/2016 G-02 412,500


20025770 GREENVILLE 70 Solar Inverter 6/7/2016 G-02 77,000


20067671 ADAMSVILLE 7.6 Solar Inverter 1/5/2016 A-16 8,360

20157367 HOPE VALLEY 14 Solar Inverter 9/7/2016 A-16 15,400


20174457 PORTSMOUTH 1500 Wind Inverter 8/11/2016 C-06 3,600,000

20177683 NORTH SMITHFIELD 70 Solar Inverter 2/10/2016 G-02 77,000










SentRate Class

Estimated Annual

Generation - kWh

20430005 GREENE 5 Solar Inverter 3/10/2016 A-16 5,500





20494743 KINGSTON 5 Solar Inverter 1/4/2016 A-16 5,500









20558948 BRADFORD 15.2 Solar Inverter 1/12/2016 C-06 16,720








20630501 WEST WARWICK 27.3 Solar Inverter 6/1/2016 C-06 30,030








20689938 CENTRAL FALLS 3.75 Solar Inverter 4/14/2016 A-16 4,125






20727203 GLOCESTER 19.8 Solar Inverter 3/24/2016 C-06 21,780
















20817484 LINCOLN 136.2 Solar Inverter 4/13/2016 G-02 149,820







SentRate Class

Estimated Annual

Generation - kWh
















20921559 PEACE DALE 9.03 Solar Inverter 4/22/2016 C-06 9,933









20972754 SCITUATE 10 Solar Inverter 5/19/2016 A-16 11,000



































SentRate Class

Estimated Annual

Generation - kWh










21026123 GREENE 11.4 Solar Inverter 5/27/2016 C-06 12,540



















21068383 GREENE 5 Solar Inverter 5/18/2016 A-16 5,500



21086976 SOUTH KINGSTOWN 7.6 Solar Inverter 1/19/2016 A-16 8,360







21097182 FOSTER 10 Solar Inverter 8/23/2016 A-16 11,000





















SentRate Class

Estimated Annual

Generation - kWh






21212740 MIDDLETOWN 15.08 Solar Inverter 3/24/2016 C-06 16,588













21239822 L COMPTON 5 Solar Inverter 3/24/2016 C-06 5,500






21258025 WEST GREENWICH 19.995 Solar Inverter 7/14/2016 C-06 21,995



21275000 EAST PROVIDENCE 5 Solar Inverter 3/30/2016 A-60 5,500
































SentRate Class

Estimated Annual

Generation - kWh




























































SentRate Class

Estimated Annual

Generation - kWh
























































21480609 NARRAGANSETT 0.75 Solar Inverter 8/2/2016 A-16 825




SentRate Class

Estimated Annual

Generation - kWh















21548455 HOPE VALLEY 5 Solar Inverter 5/19/2016 A-16 5,500













































SentRate Class

Estimated Annual

Generation - kWh














21685303 EXETER 4 Solar Inverter 5/26/2016 C-06 4,400

21685349 WAKEFIELD 6.45 Solar Inverter 8/3/2016 C-06 7,095





















21766788 JAMESTOWN 15 Solar Inverter 8/18/2016 C-06 16,500













21813523 SCITUATE 7.6 Solar Inverter 6/20/2016 A-16 8,360











SentRate Class

Estimated Annual

Generation - kWh


21867724 NORTH SCITUATE 5 Solar Inverter 6/29/2016 A-16 5,500














































22008433 MIDDLETOWN 86.4 Solar Inverter 7/6/2016 C-06 95,040












SentRate Class

Estimated Annual

Generation - kWh




































22224010 NORTH SCITUATE 3 Solar Inverter 9/28/2016 A-16 3,300








22244862 WEST KINGSTON 7.6 Solar Inverter 8/15/2016 C-06 8,360



22273146 CUMBERLAND 15.75 Solar Inverter 12/28/2016 G-02 17,325













SentRate Class

Estimated Annual

Generation - kWh













22387319 HOPE 5 Solar Inverter 9/20/2016 A-16 5,500













22436853 ASHAWAY 6 Solar Inverter 9/27/2016 A-16 6,600





















22574338 ESMOND 5 Solar Inverter 10/27/2016 A-16 5,500













SentRate Class

Estimated Annual

Generation - kWh


22633563 WARWICK 28.8 Solar Inverter 12/27/2016 C-06 31,680







22651829 HOPKINTON 6.6 Solar Inverter 10/27/2016 A-60 7,260

































22824952 SCITUATE 6 Solar Inverter 11/23/2016 A-16 6,600


















SentRate Class

Estimated Annual

Generation - kWh


























13336848 WARWICK 100 Wind Inverter 9/7/2017 G-02 240,000

13352530 WAKEFIELD 10 Wind Inverter 2/6/2017 C-06 24,000

20042214 LINCOLN 1116 Solar Inverter 6/26/2017 C-06 1,227,600

21210567 RIVERSIDE 149.5 Solar Inverter 9/14/2017 G-02 164,450

21317586 MIDDLETOWN 180 Solar Inverter 2/16/2017 G-02 198,000


22292711 MIDDLETOWN 133.3 Solar Inverter 7/12/2017 G-02 146,630



22649881 EAST PROVIDENCE 119.9 Solar Inverter 3/9/2017 G-02 131,890

22650339 BRISTOL 28.8 Solar Inverter 3/9/2017 C-06 31,680


23053065 JOHNSTON 108 Solar Inverter 8/23/2017 G-02 118,800


23373767 RICHMOND 3000 Solar Inverter 12/28/2017 C-06 3,300,000

23374056 RICHMOND 1500 Solar Inverter 12/22/2017 C-06 1,650,000



23755978 JOHNSTON 86.4 Solar Inverter 12/13/2017 G-02 95,040



24142719 COVENTRY 25 Solar Inverter 6/15/2017 C-06 27,500

24561970 TIVERTON 22.8 Solar Inverter 10/3/2017 C-06 25,080





153939 WYOMING 9 Solar Inverter 11/20/2017 A-16 9,900







SentRate Class

Estimated Annual

Generation - kWh







160436 GLENDALE 10.4 Solar Inverter 2/24/2017 A-16 11,440

159789 BRISTOL 9 Solar Inverter 2/15/2017 C-06 9,900



























162073 GLOCESTER 5 Solar Inverter 2/8/2017 A-16 5,500








162384 WYOMING 9 Solar Inverter 2/24/2017 A-16 9,900

















SentRate Class

Estimated Annual

Generation - kWh












148248 HOPKINTON 6 Solar Inverter 3/28/2017 A-16 6,600














155498 CENTRAL FALLS 3.6 Solar Inverter 4/6/2017 A-60 3,960

























152643 FORESTDALE 3 Solar Inverter 4/14/2017 A-16 3,300









SentRate Class

Estimated Annual

Generation - kWh

































157200 GLOCESTER 10 Solar Inverter 5/3/2017 C-06 11,000

154897 EAST PROVIDENCE 19.8 Solar Inverter 5/3/2017 C-06 21,780


























SentRate Class

Estimated Annual

Generation - kWh






















153211 GLOCESTER 10 Solar Inverter 5/30/2017 A-16 11,000






162266 CAROLINA 3.8 Solar Inverter 6/2/2017 A-16 4,180




















153303 GREENVILLE 3 Solar Inverter 6/21/2017 A-16 3,300












SentRate Class

Estimated Annual

Generation - kWh

































153584 MANVILLE 5 Solar Inverter 8/2/2017 A-16 5,500





















160977 CRANSTON 10 Solar Inverter 8/25/2017 C-06 11,000



161037 HOPKINTON 3.6 Solar Inverter 8/25/2017 A-16 3,960



SentRate Class

Estimated Annual

Generation - kWh








156414 CENTRAL FALLS 6 Solar Inverter 9/1/2017 A-16 6,600


























156318 CENTRAL FALLS 5 Solar Inverter 10/27/2017 A-16 5,500



















154749 ASHAWAY 3.6 Solar Inverter 11/13/2017 A-60 3,960







SentRate Class

Estimated Annual

Generation - kWh





157344 PRUDENCE ISL 4.25 Solar Inverter 12/4/2017 A-16 4,675
























155036 SLATERSVILLE 10.4 Solar Inverter 11/29/2017 A-16 11,440


159209 KENYON 10.44 Solar Inverter 12/15/2017 A-16 11,484






159222 NEWPORT 24.64 Solar Inverter 3/9/2017 G-02 27,104

















152317 MISQUAMICUT 3 Solar Inverter 12/14/2017 A-16 3,300






SentRate Class

Estimated Annual

Generation - kWh

150305 BRADFORD 10.4 Solar Inverter 11/20/2017 A-16 11,440

























157372 CLAYVILLE 8 Solar Inverter 11/20/2017 A-16 8,800


157380 CHARLESTOWN 11.5 Solar Inverter 1/6/2017 C-06 12,650

157382 FOSTER 10 Solar Inverter 1/6/2017 C-06 11,000

157386 BRADFORD 4 Solar Inverter 1/4/2017 A-16 4,400










157409 ESMOND 7.68 Solar Inverter 1/10/2017 A-16 8,448




















SentRate Class

Estimated Annual

Generation - kWh




























165846 Pawtucket 10.4 Solar Inverter 2/3/2017 A-16 11,440



Totals 39,319.81 63,178,407


Schedule A

SC-18




Schedule ASC-18

LTCRER Reconciliation and Calculation of Proposed LTC Factor

Long-Term Contracting For Renewable Energy Recovery (LTCRER) ReconciliationFor the Period January 1, 2017 through December 31, 2017

Reconciliation and LTCRER Factor Calculation

Beginning EndingOver(Under) Monthly Over(Under)

Recovery Balance Revenue Expense Adjustments Over(Under) Recovery Balance(a) (b) (c) (d) (e) (f)

Jan-17 $0 $1,401,254 $2,706,855 ($510,905) ($1,816,507) ($1,816,507)Feb-17 ($1,816,507) $3,239,487 $3,994,003 ($754,515) ($2,571,022)Mar-17 ($2,571,022) $3,177,466 $4,660,780 ($1,483,314) ($4,054,336)Apr-17 ($4,054,336) $3,158,409 $3,265,300 ($969,272) ($1,076,163) ($5,130,499)

May-17 ($5,130,499) $2,814,427 $4,305,904 ($1,491,477) ($6,621,976)Jun-17 ($6,621,976) $3,164,012 $4,887,404 ($1,723,392) ($8,345,369)Jul-17 ($8,345,369) $3,861,099 $1,693,179 $2,167,921 ($6,177,448)

Aug-17 ($6,177,448) $3,936,142 $3,655,444 $280,697 ($5,896,751)Sep-17 ($5,896,751) $3,565,020 $3,893,033 ($328,012) ($6,224,763)Oct-17 ($6,224,763) $3,228,040 $2,738,422 $489,618 ($5,735,145)

Nov-17 ($5,735,145) $3,136,915 $4,585,221 ($1,448,306) ($7,183,451)Dec-17 ($7,183,451) $3,153,492 $3,111,114 $42,378 ($7,141,073)Jan-18 ($7,141,073) $2,218,660 $2,218,660 ($4,922,414)

$40,054,422 $43,496,658 ($1,480,178) ($4,922,414) ($4,922,414)

(1) Interest ($35,441)


(3) Interest During Recovery Period ($53,856)

(4) Ending Balance Including Interest During the Recovery Period ($5,011,711)

(5) Forecasted kWhs for the period April 1, 2018 through March 31, 2019 7,292,662,088

(6) Unadjusted charge per kWh $0.00068

(7) Adjustment for Uncollectible Allowance $0.00000

(8) Proposed LTC Recovery Reconciliation Factor Effective April 1, 2018 $0.00068

(9) currently effective LTC Recovery Factor $0.00519

(10) LTC Recovery Factor Effective April 1, 2018 $0.00587

(a) (d)

(b) Page 3, column (g)(c) Page 4, column (j) (e) column (b) - column (c) + column (d)

(f) column (a) + column (e)

(1) (5) per Company forecast(6) Line (4) ÷ Line (5), truncated to 5 decimal places(7)

(2) ending balance plus interest on line (1) (8) Line (6) + Line (7)(3) Page 2 (9) per LTC Recovery Factor filing, November 2017(4) Line (2) + Line (3) (10) Line (8) + Line (9)

{[(Beginning balance of ($000,000) + Ending balance of -$4,922,413.65) ÷ 2] x average short term interest rate of 1.4400% Line (6) x the Uncollectible rate of 1.25%, truncated to 5 decimal

places

January 2017; Cumulative ISO LTC and QF Energy Sale Resettlement Corrections, incl. interest. Prior month's column (f)

April 2017; Page 6, Remaining Balance from Over(Under) Recovery incurred during 2015


Beginning Ending Money PoolBalance Recovery Balance Rate Interest

(a) (b) (c) (d) (e)

Jan-18 ($4,957,855) ($4,957,855) 1.44% ($5,949)Feb-18 ($4,963,804) ($4,963,804) 1.44% ($5,957)Mar-18 ($4,969,761) ($4,969,761) 1.44% ($5,964)Apr-18 ($4,975,725) ($414,644) ($4,561,081) 1.44% ($5,722)May-18 ($4,566,803) ($415,164) ($4,151,639) 1.44% ($5,231)Jun-18 ($4,156,870) ($415,687) ($3,741,183) 1.44% ($4,739)Jul-18 ($3,745,922) ($416,214) ($3,329,708) 1.44% ($4,245)

Aug-18 ($3,333,954) ($416,744) ($2,917,210) 1.44% ($3,751)Sep-18 ($2,920,960) ($417,280) ($2,503,680) 1.44% ($3,255)Oct-18 ($2,506,935) ($417,823) ($2,089,113) 1.44% ($2,758)Nov-18 ($2,091,870) ($418,374) ($1,673,496) 1.44% ($2,259)Dec-18 ($1,675,755) ($418,939) ($1,256,817) 1.44% ($1,760)Jan-19 ($1,258,576) ($419,525) ($839,051) 1.44% ($1,259)Feb-19 ($840,309) ($420,155) ($420,155) 1.44% ($756)Mar-19 ($420,911) ($420,911) $0 1.44% ($253)

($53,856)

(a) Jan-18 per Page 1, line (2). Feb-18 through Mar-19, Column (c) + Column (e) of previous month(b) For Apr-2018, (Column (a)) ÷ 12. For May-2018, (Column (a)) ÷ 11, etc.(c) Column (a) - Column (b)(d) Average CY17 Rate for Money Pool(e) (Column (a) + Column (c) ÷ 2) x (Column (d) ÷ 12)

Calculation of Interest During Recovery Period

Long-Term Contracting For Renewable Energy Recovery (LTCRER) ReconciliationReconciliation and LTCRER Factor Calculation



Revenue

TotalRenewable Net

Energy LTCRERDistribution Net LTCRER Net Revenue

Charge Metering LTCRER Reconciliation LTCRER Uncollectible Adjusted forRevenue Revenue Revenue Revenue Revenue Revenue Uncollectibles

(a) (b) (c) (d) (e) (f) (g)

(1) Jan-17 $1,729,359 $18,589 $1,710,770 $308,041 $1,402,729 $17,534 $1,401,254Feb-17 $4,017,234 $41,928 $3,975,306 $694,812 $3,280,494 $41,006 $3,239,487Mar-17 $3,936,840 $40,927 $3,895,913 $678,226 $3,217,687 $40,221 $3,177,466Apr-17 $3,919,106 $79,913 $3,839,193 $640,804 $3,198,389 $39,980 $3,158,409

May-17 $3,504,441 $119,452 $3,384,989 $534,937 $2,850,053 $35,626 $2,814,427Jun-17 $3,950,718 $136,294 $3,814,424 $610,361 $3,204,063 $40,051 $3,164,012Jul-17 $4,799,415 $162,358 $4,637,057 $727,083 $3,909,974 $48,875 $3,861,099

Aug-17 $4,882,944 $163,734 $4,719,210 $733,244 $3,985,966 $49,825 $3,936,142Sep-17 $4,422,634 $148,311 $4,274,323 $664,176 $3,610,147 $45,127 $3,565,020Oct-17 $4,004,761 $134,323 $3,870,437 $601,536 $3,268,902 $40,861 $3,228,040Nov-17 $3,892,097 $130,602 $3,761,494 $584,872 $3,176,623 $39,708 $3,136,915Dec-17 $3,913,003 $131,354 $3,781,649 $588,240 $3,193,409 $39,918 $3,153,492

(2) Jan-18 $2,751,360 $92,113 $2,659,248 $412,504 $2,246,744 $28,084 $2,218,660

$49,723,912 $1,399,900 $48,324,012 $7,778,834 $40,545,178 $506,815 $40,054,422

(1) reflects revenue associated with usage on and after January 1

(2) reflects revenue associated with usage prior to January 1

(a) per Company revenue reports (f) column (e) x 1.25%

(b) per Schedule ASC-16, Page 2, Column (b) (g) column (e) - column (f)

(c) column (a) - column (b)(d) Page 6, Column (b) for January 2017 - March 2017, Page 5, Column (b) for May 2017 - Dec 2017(e) column (c) - column (d)

Column (g) includes an adjustment of $16,059 to increase revenue plus interest associated with an account which was under-billed due to incorrect meter programming



Expense Summary

Capacity Contract Cost Energy Above(Below) Other FCMTotal Contract Revenue Less Capacity Market REC Market Charges & Admin Total

Cost Received Revenue Proceeds Proceeds Cost (Credits) Remuneration Expenses Costs(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

Jan-17 $4,950,078 $63,825 $4,886,254 $1,149,583 $1,164,188 $2,572,483 $134,372 $0 $2,706,855Feb-17 $4,727,380 $64,051 $4,663,329 $797,568 $0 $3,865,761 $128,242 $0 $3,994,003Mar-17 $5,707,384 $64,051 $5,643,333 $1,137,745 $0 $4,505,588 $155,192 $0 $4,660,780Apr-17 $5,229,001 $64,051 $5,164,950 $976,717 $1,064,969 $3,123,264 $142,036 $0 $3,265,300

May-17 $5,080,484 $64,051 $5,016,433 $872,138 $0 $4,144,294 $137,952 $23,658 $4,305,904Jun-17 $5,757,814 $197,182 $5,560,632 $831,748 $0 $4,728,884 $152,917 $5,603 $4,887,404Jul-17 $5,090,375 $197,182 $4,893,193 $1,043,844 $2,260,837 $1,588,512 ($32,425) $134,563 $2,529 $1,693,179

Aug-17 $4,385,539 $197,182 $4,188,356 $650,724 $0 $3,537,632 $115,180 $2,633 $3,655,444Sep-17 $4,639,463 $205,554 $4,433,909 $662,808 $0 $3,771,100 $121,932 $0 $3,893,033Oct-17 $4,928,974 $203,702 $4,725,273 $817,003 $1,247,892 $2,660,378 ($55,500) $129,945 $3,599 $2,738,422

Nov-17 $5,700,987 $203,216 $5,497,771 $1,063,739 $0 $4,434,033 $151,189 $0 $4,585,221Dec-17 $5,583,802 $203,216 $5,380,586 $2,417,439 $0 $2,963,148 $147,966 $0 $3,111,114

$61,781,282 $1,727,265 $60,054,017 $12,421,055 $5,737,885 $41,895,077 ($87,925) $1,651,485 $38,021 $43,496,658

(a) per contract invoice(b) per contract invoice(c) column (a) - column (b)(d) from ISO invoice(e) per Company records (number of RECs received x transfer price)(f) column (c) - column (d) - column (e)(g) Performance Guarantee Deposit refunds for terminated contracts(h) column (c) x 2.75%(i) ISO-NE Forward Capacity Market Administrative Expense as approved in RIPUC Docket No. 4676(j) column (f) + column (g) + column (h) + column (i)


Long-Term Contracting For Renewable Energy ReconciliationFor the Period January 1, 2017 through December 31, 2017

Status of Prior Period Over(Under) Recovery

Section 1Incurred: January 1, 2016 through December 31, 2016Recovery Period: April 1, 2017 through March 31, 2018

Beginning Over(Under)Over(Under) Adjustment Over(Under) Ending

Recovery Factor Uncollectible Net Recovery Interest Interest MonthlyBalance Charge/(Credit) Expenses Recovery Balance Balance Rate Interest Balance

(a) (b) (c) (d) (e) (f) (g) (h) (i)Jan-17 ($7,560,228) $0 $0 $0 ($7,560,228) ($7,560,228) 1.32% ($8,316) ($7,568,544)Feb-17 ($7,568,544) $0 $0 $0 ($7,568,544) ($7,568,544) 1.35% ($8,515) ($7,577,059)Mar-17 ($7,577,059) $0 $0 $0 ($7,577,059) ($7,577,059) 1.28% ($8,082) ($7,585,141)Apr-17 ($7,585,141) $253,099 $3,164 $249,935 ($7,335,206) ($7,460,173) 1.26% ($7,833) ($7,343,039)

May-17 ($7,343,039) $534,937 $6,687 $528,250 ($6,814,789) ($7,078,914) 1.29% ($7,610) ($6,822,399)Jun-17 ($6,822,399) $610,361 $7,630 $602,732 ($6,219,667) ($6,521,033) 1.23% ($6,684) ($6,226,351)Jul-17 ($6,226,351) $727,083 $9,089 $717,995 ($5,508,357) ($5,867,354) 1.50% ($7,334) ($5,515,691)

Aug-17 ($5,515,691) $733,244 $9,166 $724,078 ($4,791,613) ($5,153,652) 1.52% ($6,528) ($4,798,141)Sep-17 ($4,798,141) $664,176 $8,302 $655,874 ($4,142,267) ($4,470,204) 1.39% ($5,178) ($4,147,445)Oct-17 ($4,147,445) $601,536 $7,519 $594,016 ($3,553,428) ($3,850,437) 1.72% ($5,519) ($3,558,947)

Nov-17 ($3,558,947) $584,872 $7,311 $577,561 ($2,981,387) ($3,270,167) 1.71% ($4,660) ($2,986,047)Dec-17 ($2,986,047) $588,240 $7,353 $580,887 ($2,405,160) ($2,695,603) 1.71% ($3,841) ($2,409,001)Jan-18 ($2,409,001) $729,063 $9,113 $719,950 ($1,689,052) ($2,049,026) 1.73% ($2,954) ($1,692,006)Feb-18 ($1,692,006) $0 $0 $0 ($1,692,006) ($1,692,006) 1.44% ($2,030) ($1,694,036)Mar-18 ($1,694,036) $0 $0 $0 ($1,694,036) ($1,694,036) 1.44% ($2,033) ($1,696,069)Apr-18 ($1,696,069) $0 $0 $0 ($1,696,069) ($1,696,069) 1.44% ($2,035) ($1,698,104)

(a)

(b) per company records(c) column (b) x 1.25% (uncollectible percentage)(d) column (b) - column (c)(e) column (a) + column (d)(f) [column (a) + column (d)] ÷ 2(g) Money Pool interest rate(h) column (f) x (column (g) ÷ 12)(i) column (e) + column (h)

Section 2. Calculation of LTC Reconciliation Factor Revenue

LTC LTC kWh Reconciliation Reconciliation

Mo/Yr Deliveries Factor Factor Rev(i) (j) (k)

Apr-17 245,727,028 $0.00103 $253,099May-17 519,355,947 $0.00103 $534,937Jun-17 592,583,630 $0.00103 $610,361Jul-17 705,905,912 $0.00103 $727,083

Aug-17 711,887,017 $0.00103 $733,244Sep-17 644,830,957 $0.00103 $664,176Oct-17 584,015,205 $0.00103 $601,536

Nov-17 567,836,612 $0.00103 $584,872Dec-17 571,106,445 $0.00103 $588,240Jan-18 707,828,107 $0.00103 $729,063Feb-18 - $0.00103 $0Mar-18 - $0.00103 $0Apr-18 - $0.00103 $0

(i) per Company revenue reports(j) Reconciliation Factor in effect April 1, 2017 through March 31, 2018(k) column (i) x column (j)

from previous month column (h); beginning balance per Docket No. 4691 Annual Rate Filing, filed February 2017, Schedule ASC-18, page 1, Line (2)


Long-Term Contracting For Renewable Energy ReconciliationFor the Period January 1, 2017 through December 31, 2017

Status of Prior Period Over(Under) Recovery

Section 1Incurred: January 1, 2015 through December 31, 2015Recovery Period: April 1, 2016 through March 31, 2017

Beginning Over(Under)Over(Under) Adjustment Over(Under) Ending

Recovery Factor Uncollectible Net Recovery Interest Interest MonthlyBalance Charge/(Credit) Expenses Recovery Balance Balance Rate Interest Balance

(a) (b) (c) (d) (e) (f) (g) (h) (i)Jan-16 ($9,436,608) $0 $0 $0 ($9,436,608) ($9,436,608) 0.90% ($7,077) ($9,443,685)Feb-16 ($9,443,685) $0 $0 $0 ($9,443,685) ($9,443,685) 0.93% ($7,319) ($9,451,004)Mar-16 ($9,451,004) $0 $0 $0 ($9,451,004) ($9,451,004) 0.97% ($7,640) ($9,458,644)Apr-16 ($9,458,644) $301,615 $3,770 $297,845 ($9,160,799) ($9,309,722) 0.87% ($6,750) ($9,167,549)

May-16 ($9,167,549) $587,786 $7,347 $580,439 ($8,587,110) ($8,877,329) 1.12% ($8,286) ($8,595,395)Jun-16 ($8,595,395) $709,063 $8,863 $700,199 ($7,895,196) ($8,245,296) 0.96% ($6,596) ($7,901,792)Jul-16 ($7,901,792) $802,171 $10,027 $792,143 ($7,109,649) ($7,505,721) 1.16% ($7,256) ($7,116,904)

Aug-16 ($7,116,904) $912,006 $11,400 $900,606 ($6,216,298) ($6,666,601) 1.18% ($6,555) ($6,222,854)Sep-16 ($6,222,854) $861,957 $10,774 $851,182 ($5,371,672) ($5,797,263) 0.75% ($3,623) ($5,375,295)Oct-16 ($5,375,295) $677,422 $8,468 $668,954 ($4,706,340) ($5,040,818) 0.82% ($3,445) ($4,709,785)Nov-16 ($4,709,785) $625,135 $7,814 $617,321 ($4,092,464) ($4,401,124) 0.97% ($3,558) ($4,096,022)Dec-16 ($4,096,022) $676,647 $8,458 $668,189 ($3,427,832) ($3,761,927) 1.09% ($3,417) ($3,431,249)Jan-17 ($3,431,249) $741,552 $9,269 $732,283 ($2,698,967) ($3,065,108) 1.32% ($3,372) ($2,702,338)Feb-17 ($2,702,338) $694,812 $8,685 $686,127 ($2,016,211) ($2,359,275) 1.35% ($2,654) ($2,018,865)Mar-17 ($2,018,865) $678,226 $8,478 $669,748 ($1,349,117) ($1,683,991) 1.28% ($1,796) ($1,350,913)Apr-17 ($1,350,913) $387,705 $4,846 $382,858 ($968,055) ($1,159,484) 1.26% ($1,217) ($969,272)

(a)

(b) per company records(c) column (b) x 1.25% (uncollectible percentage)(d) column (b) - column (c)(e) column (a) + column (d)(f) [column (a) + column (d)] ÷ 2(g) Money Pool interest rate(h) column (f) x (column (g) ÷ 12)(i) column (e) + column (h)

Section 2. Calculation of LTC Reconciliation Factor Revenue

LTC LTC kWh Reconciliation Reconciliation

Mo/Yr Deliveries Factor Factor Rev(i) (j) (k)

Apr-16 260,012,717 $0.00116 $301,615May-16 506,712,348 $0.00116 $587,786Jun-16 611,260,814 $0.00116 $709,063Jul-16 691,526,304 $0.00116 $802,171

Aug-16 786,212,317 $0.00116 $912,006Sep-16 743,066,106 $0.00116 $861,957Oct-16 583,984,662 $0.00116 $677,422Nov-16 538,909,651 $0.00116 $625,135Dec-16 583,316,761 $0.00116 $676,647Jan-17 639,269,015 $0.00116 $741,552Feb-17 598,976,060 $0.00116 $694,812Mar-17 584,677,659 $0.00116 $678,226Apr-17 334,228,196 $0.00116 $387,705

(i) per Company revenue reports(j) Reconciliation Factor in effect April 1, 2016 through March 31, 2017(k) column (i) x column (j)

from previous month column (h); beginning balance per Docket No. 4599 Annual Rate Filing, filed February 2016, Schedule ASC-18, page 1, Line (2); Includes additional $694,519 in under-recovery due to overstated LTCRER revenue for the months of Jan. 2015 through April 2015 on pages 1 and 3 of Docket No. 4599 AnnuRate Filing, filed February 2016, Schedule ASC-18


Schedule A

SC-19




Schedule ASC-19

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150

$20.

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%

300

$34.

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400

$43.

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4.77

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9$8

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500

$52.

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2.17

$50.

87$4

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$107

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($0.

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$3.2

9$0

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$3.0

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2.9%

9.6%

600

$61.

69$5

7.09

$4.9

5$1

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1.29

$61.

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$127

.43

($0.

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$3.9

5$0

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$3.7

0-0

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700

$70.

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6.61

$5.7

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1$7

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$71.

22$5

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$147

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($0.

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$4.6

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%

1,20

0$1

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$240

.59

$115

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$122

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e (1

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C-9

, Pag

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of

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Ren

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of C

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Ser

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GE

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(b)

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(e)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

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150

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600

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700

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ive

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nd S

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of R

ates

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vice

tari

ff, R

.I.P

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. No.

209

6, e

ffec

tive

1/1

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umn

(p):

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es (

1) th

roug

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1), (

19):

Sum

mar

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ail D

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Rat

es, R

.I.P

.U.C

. No.

209

5, e

ffec

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18. L

ines

(20

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d (2

3): S

umm

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of R

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d O

ffer

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ff, R

.I.P

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. No.

209

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1/1

/201

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g T

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Ren

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Testim

ony of

Polin

a V. D

emers


RIPUC DOCKET NO. 4805 2018 ELECTRIC RETAIL RATE FILING

WITNESS: POLINA V. DEMERS

PRE-FILED DIRECT TESTIMONY

OF

POLINA V. DEMERS



WITNESS: POLINA V. DEMERS

Table of Contents

I. Introduction and Qualifications ...................................................................................... 1

II. Purpose of Testimony ....................................................................................................... 2

III. Summary of Transmission Services Provided to Narragansett .................................... 2

Explanation of ISO/RTO Tariff Services, Rates, and Charges .................................... 4

Explanation of NEP Local Services and Charges ........................................................ 11

IV. Estimated Transmission Expenses ................................................................................ 15

V. Explanation of Primary Changes from Last Year’s Forecasted Expenses ............... 20

VI. Conclusion ....................................................................................................................... 22



WITNESS: POLINA V. DEMERS PAGE 1 OF 22

I. Introduction and Qualifications 1

Q. Please state your name and business address. 2

A. My name is Polina V. Demers. My business address is 40 Sylvan Road, Waltham 3

Massachusetts 02451. 4

5

Q. By whom are you employed and in what capacity? 6

A. I am currently a Senior Analyst in the Regulation and Pricing Department for National 7

Grid USA Service Company, Inc. (Service Co). Service Co. is a subsidiary of National 8

Grid USA. My duties include performing rate-related services for The Narragansett 9

Electric Company d/b/a National Grid (Narragansett or Company). 10

11

Q. Please describe your educational and professional background. 12

A. I graduated from University of Massachusetts in North Dartmouth, Massachusetts with a 13

Bachelor of Science degree in Accounting and from University of Massachusetts in 14

Lowell, Massachusetts with a Master in Accounting. I have been at National Grid USA 15

for four years. As Senior Analyst in the Regulation and Pricing Department, I am 16

involved in most New England transmission-related pricing matters that impact the 17

Company, including the Company’s current Transmission Service Cost Adjustment 18

docket that is pending before the Rhode Island Public Utilities Commission (PUC). 19

20




Q. Have you previously testified before the PUC? 1

A. No. I have not previously testified before the PUC. 2

3

II. Purpose of Testimony 4

Q. What is the purpose of your testimony? 5

A. My testimony addresses the Company’s estimated 2018 transmission expenses, including 6

administrative expenses charged to the Company by ISO New England Inc (ISO-NE). 7

First, I will summarize the various transmission services provided to Narragansett and 8

how Narragansett pays for such services. Second, I will provide testimony supporting the 9

forecast of transmission expenses that Narragansett expects to incur in 2018, which is 10

summarized in Schedule PVD-1. As described more fully in the second part of my 11

testimony, the Company expects that there will be a decrease of $4,638,920 in 12

prospective transmission expenses compared to the forecast provided for calendar year 13

2017 in PUC Docket Nos. 4691 and 4605. 14

15

III. Summary of Transmission Services Provided to Narragansett 16

Q. Please explain the history of transmission service provided to Narragansett under 17

rate schedules approved by the Federal Energy Regulatory Commission (FERC). 18

A. Effective January 1, 1998, Narragansett began receiving transmission services on behalf 19

of its entire customer base, under two tariffs: NEPOOL’s FERC Electric Tariff No. 1 20

(NEPOOL Tariff) and NEP’s FERC Electric Tariff No. 9 (NEP T-9 Tariff). 21




Additionally, effective January 1, 1999, Narragansett began taking service under ISO-1

NE’s FERC Electric Tariff No. 1 (ISO-NE Tariff). 2

3

Effective February 1, 2005, FERC issued an order authorizing ISO-NE to begin operating 4

as a Regional Transmission Organization (RTO), and at that time, ISO-NE replaced 5

NEPOOL as the transmission provider in New England. The new ISO-NE Transmission, 6

Markets and Services Tariff (ISO/RTO Tariff) replaced the three separate tariffs referred 7

to above by aggregating them into a single, omnibus tariff. As a result, NEP and ISO-NE 8

as the RTO now charge Narragansett under the ISO/RTO Tariff. 9

10

Therefore, the prospective charges to the Company are separately identified as (1) NEP 11

local charges, (2) ISO-NE regional charges, and (3) ISO-NE administrative charges. 12

13

Q. Please describe further the types of transmission services that are billed to 14

Narragansett under the ISO/RTO Tariff. 15

A. New England’s transmission rates utilize a highway/local pricing structure. Under this 16

structure, Narragansett receives regional transmission service over “highway” 17

transmission facilities under Section II of the ISO/RTO Tariff, and receives local 18

transmission service over local transmission facilities under Schedule 21 of the ISO/RTO 19

Tariff. Additionally, ISO-NE provides transmission scheduling and market 20

administration services under Section IV.A of the ISO/RTO Tariff. 21




Explanation of ISO/RTO Tariff Services, Rates, and Charges 1

Q. Please explain the services provided to Narragansett under the ISO/RTO Tariff. 2

A. Section II of the ISO/RTO Tariff provides access over New England’s looped 3

transmission facilities, more commonly known as Pool Transmission Facilities (PTF) or 4

bulk transmission facilities. These facilities serve as New England’s electric transmission 5

“highway”, and the service provided over these facilities is referred to as Regional 6

Network Service (RNS). In addition, as described in detail later in this testimony, the 7

ISO/RTO Tariff provides for Blackstart, Reactive Power, Scheduling, System Control, 8

and Dispatch and Administrative Services. 9

10

Q. How are the costs for RNS recovered? 11

A. The ISO-NE RNS Rate (RNS Rate) recovers the aggregate revenue requirement for 12

certain PTF facilities owned by New England Transmission Owners (NETOs). The RNS 13

Rate is determined annually in accordance with a FERC-approved formula. Pursuant to a 14

NEPOOL Settlement dated April 7, 1999, which was incorporated into the ISO/RTO 15

Tariff, the RNS Rate has transitioned from zonal rates to a single, “postage stamp” rate in 16

New England. 17

18




Q. Please describe the ISO-NE Blackstart, Reactive Power and Scheduling, System 1

Control and Dispatch Services that are included in the ISO/RTO Tariff. 2

A. ISO-NE Blackstart Service, also known as System Restoration and Planning Service from 3

Generators, is necessary to ensure the continued reliable operation of the New England 4

transmission system. This service allows for the designation of generators with the 5

capability of supplying load and ability to start without an outside electrical supply to re-6

energize the transmission system following a system-wide blackout. 7

8

Reactive Power Service, also known as Reactive Supply and Voltage Control from 9

Generation Sources Service, is necessary to maintain transmission voltages on the ISO-10

NE transmission system within acceptable limits and requires that generation facilities be 11

operated to produce or absorb reactive power. This service must be provided for each 12

transaction on the ISO-NE transmission system. The amount of reactive power support 13

that must be supplied for transactions is based on the support necessary to maintain 14

transmission voltages within limits generally accepted and is consistently sustained in the 15

region. 16

17

Finally, Scheduling, System Control, and Dispatch Service (Scheduling & Dispatch 18

Service) includes the services required to schedule the movement of power through, out 19

of, within, or into the ISO-NE Control Area over the PTF and to maintain system control. 20




Scheduling & Dispatch Service also provides for the recovery of certain charges that 1

reflect expenses incurred in the operation of satellite dispatch centers. 2

3

Q. How are the ISO-NE charges for Blackstart and Reactive Power services charged to 4

Narragansett? 5

A. Each month, ISO-NE assesses charges for Blackstart and Reactive Power services to 6

Narragansett based on Narragansett’s proportionate share of the Regional Network Load 7

to ISO-NE’s total Regional Network Load. The monthly Blackstart charge includes 8

Critical Infrastructure Protection (CIP) payments applicable to Blackstart generators. 9

CIP payments are made to existing Blackstart generators based upon proxy costs in 10

compliance with the CIP standards of the North American Electric Reliability Corporation 11

(NERC). Blackstart CIP payments are applicable to Blackstart generators that are 12

designated by ISO-NE as Northeast Power Coordinating Council (NPCC) Key Facilities 13

and provide annual confirmation to the ISO that they are incurring CIP-related costs. The 14

allocation of ISO-NE’s total Blackstart CIP costs to Narragansett is based similarly on 15

Narragansett’s proportionate share of the total Regional Network Load. The monthly 16

Reactive Power charge includes payments to generators that are dispatched down by, or at 17

the request of, the ISO-NE, or a local control center for the purpose of providing Reactive 18

Power service. Generators that provide Reactive Supply service to the transmission system 19

are compensated by different mechanisms pursuant to Section II.4 and Schedule 2 of the 20

ISO/RTO Tariff. The hourly charges for Reactive Power service to generators are 21




allocated to Narragansett based on its proportionate share of the total Regional Network 1

Load and Reserved Capacity. 2

3

Q. How are the charges for Scheduling & Dispatch Service charged to Narragansett? 4

A. Charges for Scheduling & Dispatch Service are based on the expenses ISO-NE incurs 5

and by the individual transmission owners in the operation of local control dispatch 6

centers or otherwise to provide Scheduling & Dispatch Service. 7

8

The expenses that ISO-NE incurs to provide these services are recovered under Section 9

IV.A, Schedule 1 of the ISO/RTO Tariff. These costs are allocated to Narragansett each 10

month based on the FERC-approved fixed rate for the month multiplied by 11

Narragansett’s monthly Regional Network Load. 12

13

The aggregate costs that NETOs incur to provide Scheduling & Dispatch Service over 14

PTF facilities, including the costs of operating local control centers, are recovered under 15

Section II, Schedule 1 of the ISO/RTO Tariff. These costs are allocated to Narragansett 16

each month based on a formula rate that is determined each year based on the prior year’s 17

costs incurred multiplied by Narragansett’s monthly Regional Network Load. 18

19

The costs of Scheduling & Dispatch Service that the individual transmission owners 20

incur for transmission service over transmission facilities other than PTF are charged 21




under Schedule 21 of the ISO/RTO Tariff. Thus, there are three types of Scheduling & 1

Dispatch Service costs that are similar, but which are charged to Narragansett through 2

three different tariff mechanisms. 3

4

Q. What administrative services and/or charges flow through to Narragansett under 5

Section IV.A of the ISO/RTO Tariff? 6

A. There are five different charges billed to Narragansett under Section IV.A of the 7

ISO/RTO Tariff under Schedule 1, Schedule 2, Schedule 3, Schedule 4, and Schedule 5. 8

As described above, Schedule 1 provides for one component of the administration of 9

Scheduling & Dispatch. Schedule 2, Energy Administrative Service, includes the core 10

operation of the energy market, generation dispatch, and energy accounting. Schedule 3, 11

Reliability Administrative Service, administers the reliability markets and provides other 12

reliability and informational services. Schedule 4 of the ISO/RTO Tariff provides for the 13

collection of FERC Annual Charges. Under Schedule 5, ISO-NE acts as the billing and 14

collection agent for the New England States Committee on Electricity’s (NESCOE’s) 15

annual budget. 16

17




Q. Please explain the background for the inclusion of the NESCOE charges under 1

Schedule 5 of the ISO/RTO Tariff, Section IV.A. 2

A. NESCOE was established by a memorandum of understanding between ISO-NE and 3

NEPOOL and approved by FERC for funding through the ISO/RTO Tariff in the Fall of 4

2007. NESCOE created a formal role for the six New England states’ participation on an 5

ongoing basis in the decision-making process of the RTO. NESCOE represents the 6

policy perspectives of the New England Governors and their collective interests in 7

promoting a regional electric system that ensures the lowest reasonable long-term costs 8

for customers while maintaining reliable service and environmental quality. 9

10

Q. How are the administrative charges under Section IV.A. of the ISO/RTO Tariff 11

assessed? 12

A. With the exception of charges under Schedule 4, ISO-NE assesses the charges in Section 13

IV.A based upon stated rates pursuant to the ISO/RTO Tariff. These stated rates are set 14

annually when ISO-NE files a revised budget and cost allocation proposal to become 15

effective on January 1 of each year. Under Schedule 1 and Schedule 5, the stated rate for 16

these services is multiplied by Narragansett’s Regional Network Load as part of ISO-17

NE’s monthly billing process. 18

19

The ISO-NE budget and cost allocation proposal filed on October 16, 2017 reported the 20

net revenue requirement for Schedule 1 totaling $42,226,601 after the true-up. As a 21




result, ISO-NE’s Schedule 1 rate was set at $0.17886 per KW/month for all regional 1

network customers and at $0.00025 per KW for each hour of service for transmission 2

customers receiving through or out service. 3

4

The total fiscal year 2018 NESCOE budget for Schedule 5 charges is $2,282,317, which 5

is offset by a credit true-up for actual costs and collections in prior years of $752,672, for 6

a total net NESCOE Revenue Requirement of $1,529,645. NESCOE’s per KW/month 7

charge for 2018 is set at $0.00648. 8

9

The allocation of Schedule 2 charges is based upon various billing units. The rates under 10

ISO Schedule 2 are adjusted annually effective January 1 of each year based on the net 11

revenue requirement. The 2018 net revenue requirement for Schedule 2 is $92,344,604 12

after the true-up. Charges assessed to the Company under ISO-NE’s Schedule 2 are 13

recovered through the Standard Offer Service charge and base distribution rates 14

depending on the type of transaction. 15

16

Schedule 3 charges for Market Participants are based on the participant’s real-time non-17

coincident peak load obligation (Real-Time NCP Load Obligation) for the month. Market 18

Participants who have exports will be charged based on their hourly scheduled 19

Megawatts of exports in the month. The rates under ISO-NE’s Schedule 3 are adjusted 20

annually effective January 1 of each year based on the net revenue requirement. The 21




2018 net revenue requirement for Schedule 3 is $ 60,977,048 after the true-up. The 2018 1

Real-Time NCP Load Obligation rate is $ 0.22461 per kilowatt-month. The 2018 export 2

rate is $0.48 per MWh. 3

4

Schedule 4 charges are based upon FERC’s total assessment to the New England Control 5

Area and are directly assessed to NEP based on its proportion of total MWhs of 6

transmission (including Narragansett’s) to the total of the New England Control Areas’ 7

total MWhs. NEP, in turn, allocates a portion of the charges received under Schedule 4 8

to Narragansett through a combination of RNS and LNS rates. A portion is charged to 9

Narragansett by the ISO-NE through the RNS rate using the transmission plant allocation 10

factor and remitted to NEP based on a pro-rate share basis. NEP charges the remaining 11

amounts to the Company through the monthly Non-PTF Demand charge. 12

13

Explanation of Local NEP Services and Charges 14

Q. What services are provided to Narragansett under Schedule 21-NEP of the 15

ISO/RTO Tariff? 16

A. Schedule 21-NEP provides service over NEP’s local, non-highway transmission 17

facilities, also known as Non-PTF facilities (Non-PTF). The service provided over Non-18

PTF is referred to as Local Network Service (LNS). NEP also provides metering, 19

transformation and certain ancillary services (Other NEP Charges) to Narragansett to the 20




extent that such services are required by Narragansett and not provided under Section II 1

the ISO/RTO Tariff. 2

3

Q. Please explain the components of “Other NEP Charges” to Narragansett under 4

Schedule 21. 5

A. Other NEP Charges are comprised of Scheduling and Dispatch charges and Transformer 6

and Meter Surcharges. Each component is explained below. 7

8

Scheduling and Dispatch charges are services required to schedule the movement of 9

power through, out of, within, or into the ISO-NE Control Area over Non-PTF. 10

Narragansett purchases this service from NEP. Such charges to Narragansett are charged 11

through the Local Load Dispatch Surcharge. The Local Load Dispatch Surcharge equals 12

NEP’s monthly dispatching expenses, less any revenue NEP received from the ISO-NE 13

for load dispatching services, multiplied by the Company’s Local Network Load Ratio 14

Share. 15

16

NEP provides transformation service when a customer uses NEP-owned transformation 17

facilities to step down voltages from 69 kV or greater to a distribution voltage. NEP 18

provides metering service when a customer uses NEP-owned meter equipment to 19

measure the delivery of transmission service. NEP separately surcharges the appropriate 20

customers for these services. 21




Q. Please explain the BITS Surcharge to Narragansett under Schedule 21. 1

A. The BITS Surcharge is another NEP charge to Narragansett approved by the FERC under 2

Schedule-21-NEP of the ISO/RTO Tariff. The BITS Surcharge recovers Narragansett’s 3

allocated share of the costs for the Block Island Cable and related facilities associated 4

with the Town of New Shoreham Project. The Town of New Shoreham Project is a 5

public policy project authorized and directed by Rhode Island law, which provides that: 6

“it is in the public interest for the state to facilitate the construction of a small-7 scale offshore wind demonstration project off the coast of Block Island, including 8 an undersea transmission cable that interconnects Block Island to the mainland in 9 order to: position the state to take advantage of the economic development 10 benefits of the emerging offshore wind industry; promote the development of 11 renewable energy sources that increase the nation's energy independence from 12 foreign sources of fossil fuels; reduce the adverse environmental and health 13 impacts of traditional fossil fuel energy sources; and provide the Town of New 14 Shoreham with an electrical connection to the mainland.”1 15

16

The legislation also directs that the annual costs of these facilities “shall be recovered 17

annually through a fully reconciling rate adjustment from customers of the electric 18

distribution company [Narragansett] and/or from the Block Island Power Company or its 19

successor, subject to any federal approvals that may be required by law.” R.I. Gen. Laws § 20

39-26.1-7(f). Under Schedule 21-NEP of the ISO/RTO Tariff, the BITS Surcharge to 21

Narragansett is equal to the integrated facilities credit paid to Narragansett under NEP’s 22

FERC Electric Tariff No. 1 (IFA Facilities Credit) multiplied by Narragansett’s Load 23

Share Percentage. Narragansett’s Load Share Percentage will be equal to 1 minus 24

BIPCO’s Load Share Percentage calculated based on the load data for the prior year. The 25

1 Town of New Shoreham Project, R.I. Gen. Laws § 39-26.1-7(a). (Supp. 2010).




IFA Facilities Credit amount will be updated annually on or about the June billing month 1

of each year. The estimated monthly BITS surcharge amounts are calculated in Schedule 2

PVD-7. 3

4

The Block Island Cable was placed in commercial service on October 31, 2016 when it 5

began providing station service to the Block Island Wind Farm. Effective as of 6

November 1, 2016, NEP began charging the BITS Surcharge to Narragansett and Block 7

Island Power Company in accordance with the transmission tariffs and service 8

agreements that have been accepted by FERC for this purpose. In turn, Narragansett’s 9

costs are being passed through its Transmission Service Cost Adjustment to its retail 10

customers. Completion of the BITS project is targeted for the end of 2018. In this 11

forecast, the estimated BITS Surcharge expense to Narragansett for the period of April 12

2018 through March 2019 is based on the expected monthly gross plant investment 13

balances. 14

15

Q. How are the costs for LNS recovered? 16

A. NEP calculates its total transmission revenue requirement for PTF and Non-PTF pursuant 17

to the FERC-approved formula included in Attachment RR to Schedule 21 – NEP of the 18

ISO/RTO Tariff. The total revenue requirement is calculated and NEP credits the 19

regional revenues collected by ISO-NE for PTF through the RNS Rate against the total 20




revenue requirement to determine the net amount to be collected through NEP’s local 1

rates. LNS charges are billed monthly to local network load on a load ratio share basis. 2

3

IV. Estimated Transmission Expenses 4

Q. What is the forecast for the Company’s Narragansett’s transmission and ISO 5

expenses for 2018? 6

A. The Company estimates that its total transmission and ISO-NE expenses (including 7

certain ancillary services) for 2018 will be approximately $208.08 million, as shown in 8

Schedule PVD-1, page 1. This equates to a decrease of $ 4.64 million or 2.18% of the 9

estimated expenses underlying Narragansett’s 2017 transmission rates, as shown in 10

Schedule PVD-1, page 2. 11

12

Q. Have you estimated the Local NEP Charges to Narragansett under Schedule 21 of 13

the ISO/RTO Tariff? 14

A. Yes. Lines 1 through 3 of Schedule PVD-1, page 1, show the amount of forecasted NEP 15

local charges. The total amount of expenses is $ 55.07 million. Schedule PVD-6 shows 16

the calculation of the total NEP revenue requirement. NEP allocates Non-PTF expenses 17

to Narragansett on a load ratio share basis, as shown in Schedule PVD-5, column (1). 18

Metering and transformation charges are based on forecasted rates and are assessed to 19

Narragansett based on a per meter and peak load basis, respectively. The BITS Surcharge 20

billed to Narragansett for the period April 2018 through March 2019 is an estimated total 21




of approximately $ 21.93 million. The calculation of the monthly BITS Surcharge shown 1

on Schedule PVD-7 was based on the estimated monthly gross plant investment 2

multiplied by Narragansett’s primary distribution carrying charge of 19.43%, calculated 3

based on 2016 FERC Form 1 data, and Narragansett’s Load Share Percentage of 4

approximately 99.75%, based on calendar year 2017 load data, divided by 12. 5

6

Q. How have the PTF Component of the ISO-NE Regional Charges shown on line 4 of 7

Schedule PVD-1, page 1 been forecasted? 8

A. The PTF Component of ISO-NE Regional Charges shown on line 4 of Schedule PVD-1, 9

page 1 have been forecasted using two components: 1) the most recent 12 months of 10

monthly PTF kW Load per the Monthly Regional Network Load Report posted on the 11

ISO-NE website; and 2) actual and forecasted annual RNS rates for the respective 12

months. The monthly load is multiplied by the annual rate and divided by 12 to obtain 13

the monthly PTF Demand Charge. The resulting calculation is shown in column 2 of 14


16

For the most recent 12 months of PTF kW Load, the period of January through December 17

2017 were used. For the estimated PTF rate, two different rates have been utilized (see 18

Schedule PVD-3). For April 2018 through May 2018, the actual annual rate effective for 19

this period of $111.96 was used. The calculation of the estimated 2018-2019 PTF rate 20

on line 8 of Schedule PVD-3 was based on the forecasted PTF additions across New 21




England, as estimated by the New England transmission owners, to be included in the 1

annual formula rate effective June 1, 2018. In addition, this year’s calculation of the 2

estimated PTF rate reflects an adjustment associated with the recent change in the federal 3

corporate tax rate from 35% to 21% effective January 1st 2018. Narragansett estimates 4

that the decrease in the federal corporate tax rate will result in approximately 1.47% 5

downward adjustment to the estimated carrying charge as demonstrated on lines 3 6

through 5 of the exhibit. The adjustment to the carrying charge of (1.47%) was calculated 7

using NEP’s forecasted transmission revenue requirement from the most recent 8

Participating Transmission Owner Informational Filing in docket #RT04-2-000. The 9

estimated adjusted carrying charge multiplied by the estimated New England 10

transmission owners’ plant additions of $1.098 billion equals the forecasted annual rate 11

of $119.55 used to calculate PTF Demand Charges for the period June 2018 through 12

March 2019. Narragansett’s PTF Demand Charge is estimated at approximately $145.85 13

million. 14

15

Q. Schedule PVD-1 also includes estimated ISO-NE charges for Scheduling and 16

Dispatch. How were these costs forecasted, as shown? 17

A. The estimate for Scheduling and Dispatch Service as shown in column (3) of Schedule 18

PVD-2, page 1, was derived by using the currently effective ISO/RTO Tariff Schedule 1 19

rate of $1.80704 per kW-year, divided by 12, and further multiplied by Narragansett’s 20




monthly Regional Network Load, as shown in column (1) of Schedule PVD-2, page 1. 1

The Company estimates that it will receive an allocation of $2.23 million for 2018. 2

3

Q. How did you forecast the Blackstart costs shown on line 6 of Schedule PVD-1, page 4

1? 5

A. The Blackstart costs shown on line 6 of Schedule PVD-1, page 1, were forecasted based 6

on the most recent 12 months of actual ISO-NE charges to the Company. Using this 7

methodology, the Company estimates that it will receive an allocation of $0.78 million 8

for 2018. 9

10

Q. How did you calculate the estimate for Reactive Power costs for Narragansett as 11

shown on line 7 of Schedule PVD-1, page 1? 12

A. The estimated Reactive Power cost for the New England region was calculated by using 13

the January through December 2017 actual ISO-NE settlement reports, as shown on 14

Schedule PVD-4 (line 1). The annual rate was determined by dividing the total Reactive 15

Power costs charged in the region for that 12-month historic period by the ISO-NE’s 16

2016 Regional Network Load. The monthly rate (annual rate divided by 12) was then 17

multiplied by Narragansett’s monthly Regional Network Load for the period of January 18

through December 2017 to determine the estimated charges for Reactive Power Service. 19

Using this methodology, the Company estimates that it will receive an allocation of $1.25 20

million for 2018. 21




Q. Please explain the forecast of the ISO-NE charges shown in lines 8 through 10 of 1


A. Line 8 of Schedule PVD-1, page 1, shows the 2018 forecast of charges to Narragansett 3

under Schedule 1, Scheduling and Load Dispatch Administrative schedules through 4

Section IV.A of the ISO/RTO Tariff. The estimate is based on the ISO-NE revenue 5

requirement for Schedule 1 filed each year with FERC. ISO-NE filed its proposed 2018 6

revenue requirement with FERC on October 16, 2017. To estimate Narragansett’s 2018 7

ISO-NE Schedule 1 charges, ISO-NE’s Schedule 1 actual costs for the periods December 8

2016 through November 2017 are adjusted by an inflationary factor shown on line 16 of 9

Schedule PVD-2, page 2. This inflationary factor is intended to recognize the increase or 10

decrease in ISO-NE’s Schedule 1 net revenue requirement and the associated components 11

of that revenue requirement from the budget as filed for the previous year. 12

13

Line 9 of Schedule PVD-1, page 1 shows the estimated 2018 ISO Schedule 3 Reliability 14

Administrative Service charges through Section IV.A of the ISO/RTO Tariff. The 15

estimate is based on the ISO-NE Schedule 3 Real-Time Non-Coincidental Peak Load 16

Obligation annual rate set each year by the ISO-NE. The annual rate was filed with ISO-17

NE Capital Budget and Revised Tariff Sheets for Recovery of 2018 Administrative Costs 18

with FERC on October 16, 2017. The estimated 2018 charge to Narragansett’s was 19

calculated using the actual Narragansett’s ISO Schedule 3 charges for the periods 20

December 2016 through November 2017 adjusted by the inflationary factor shown on 21




Line 19 of Schedule PVD-2, page 2. The inflationary factor represents the change in the 1

2018 ISO Schedule 3 Non-Coincidental Peak Load Obligation rate from the previous 2

year. 3

4

Line 10 of Schedule PVD-1, page 1 shows the estimated 2018 NESCOE charges under 5

Schedule 5 of Section IV.A of the ISO/RTO Tariff. For calendar year 2018, each 6

customer that is obligated to pay the RNS rate pays each month an amount equal to the 7

product of $0.00648/kW-month multiplied by its monthly Regional Network Load for 8

that month. These charges are shown in Column (3) of Schedule PVD-2, page 2. For 9

2018, the Company’s total amount of direct ISO/RTO Tariff charges under Section IV.A, 10

Schedules 1, 3, and 5, are estimated to be $2.91 million. 11

12

Q. What is the sub-total of transmission expenses attributable to charges from the ISO-13

NE? 14

A. The sub-total of ISO-NE charges is $153.01 million, which is the sum of lines 4 through 15

10 on Schedule PVD-1, page 1. 16

17

V. Explanation of Primary Changes from Last Year’s Forecasted Expenses 18

Q. What is the impact of Narragansett’s 2018 transmission expenses? 19

A. The estimated 2018 Narragansett transmission and ISO-NE expenses of $208.08 million 20

represents a net decrease of $4.64 million from the 2017 forecast of transmission 21




expenses. This total decrease is primarily due to a decrease in the forecasted NEP local 1

charges of $9.37 million which was offset by $4.73 million increase in the ISO-NE 2

Regional Charges. The decrease of $9.37 million in NEP Local charges is primarily 3

driven by the decrease in the estimated BITS Surcharges due to the inclusion of 4

November 2016 through March 2017 surcharges in the April 2017 BITS Surcharge 5

estimate. The increase in the ISO-NE Regional Charges is primarily driven by the 6

increase in PTF Demand Charges due to the expected increased transmission investment 7

resulting in higher transmission revenue requirements by the New England transmission 8

owners. The forecasted PTF transmission plant investment expected to go “in-service” in 9

2018 across New England is $1.098 billion. . 10

11

Q. What PTF plant investment is driving the increase in the ISO-NE RNS rate 12

forecasted to be in effect June 1, 2018? 13

A. The projected RNS rate increase is due to a significant amount of capital additions 14

forecasted by the transmission owners expected to go into service in 2018. Schedule 15

PVD-3 Line 2 reflects an estimated $1.098 billion of PTF plant additions for 2018 as 16

provided by the transmission owners. This number was presented by the transmission 17

owners at the summer meeting of the NEPOOL Reliability Committee/Transmission 18

Committee. 19

20




Q. What are the major projects driving the significant level of projected PTF plant 1

additions for 2018? 2

A. Based on the October 2017 ISO-NE’s Regional System Plan Project listing, the six 3

largest transmission projects in New England with a portion expected to be placed in 4

service during 2018 are: (1) Eversource’s Greater Hartford Central Connecticut Project; 5

(2) United Illuminating Company and Eversource’s joint Southwest Connecticut 6

Reliability project; (3) Eversource’s Seacoast New Hampshire Solution project; (4) the 7

Greater Boston project jointly constructed by NEP and Eversource; (5) Vermont Electric 8

Power Company’s Connecticut River Valley Project; and (6) NEP’s Sandy Pond project. 9

10

VI. Conclusion 11

Q. Does this conclude your testimony? 12

A. Yes. 13

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WITNESS: POLINA V. DEMERS SCHEDULES

Schedules of Polina V. Demers

Schedule PVD-1 Summary of Transmission Expenses Estimated for the Year 2018

Schedule PVD-2 Summary of ISO-NE Charges Estimated for the Year 2018

Schedule PVD-3 PTF Rate Calculation Estimated for the Year 2018

Schedule PVD-4 Summary of Reactive Power Costs Estimated for the Year 2018

Schedule PVD-5 Summary of New England Power Local Charges Estimated for the Year 2018

Schedule PVD-6 Non-PTF Revenue Requirement Estimated for the Year 2018

Schedule PVD-7 Monthly BITS Surcharge Estimated for the Year 2018

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Schedule PVD-1

Summary of Transmission Expenses Estimated for the Year 2018

The Narragansett Electric Company d/b/a National Grid

RIPUC Docket No. 48052018 Electric Retail Filing

Schedule PVD-1Page 1 of 2

The Narragansett Electric CompanySummary of Transmission Expenses

Estimated for the Year 2018

Line #NEP Local Charges

1 Non-PTF Demand Charges 32,871,310 2 Other NEP Charges 273,453 3 BITS Surcharge 21,925,423

Sub-Total NEP Charges $55,070,186ISO-NE Regional Charges

4 PTF Demand Charge 145,847,743 5 Scheduling & Dispatch 2,225,931 6 Black Start 776,594 7 Reactive Power 1,249,058

Sub-Total ISO-NE Charges $150,099,326ISO-NE Administrative Charges

8 Schedule 1 - Scheduling & Dispatch 2,625,632 9 Schedule 3 - Reliability Administration Service 192,185

10 Schedule 5 - NESCOE 95,784 Sub-Total ISO-NE Admin Charges $2,913,601

11 Total Expenses Flowing Through Current Rates $208,083,113

Line 1 = PVD-5: Column (2), Line 13Line 2 = PVD-5: Sum of Column (3) through (5), Line 13 Line 3 = PVD-5: Column (6), Line 13Line 4 = PVD-2, Pg 1: Column (2), Line 13Line 5 = PVD-2, Pg 1: Column (3), Line 13Line 6 = PVD-2, Pg 1: Column (4), Line 13Line 7 = PVD-2, Pg 1: Column (5), Line 13Line 8 = PVD-2, Pg 2: Column (1), Line 13Line 9 = PVD-2, Pg 2: Column (2), Line 13Line 10 = PVD-2, Pg 2: Column (3), Line 13Line 11 = Sum of Lines 1 through 10




February 2017 February 2018 Yr/YrLine # Retail Filing Retail Filing Incr/(Decr)

NEP Local Charges1 Non-PTF Demand Charges 31,259,601$ 32,871,310$ 1,611,709$ 2 Other NEP Charges 496,093 273,453 (222,640) 3 BITS Surcharge 32,680,356 21,925,423 (10,754,933)

4 Subtotal 64,436,050$ 55,070,186$ (9,365,864)$

ISO-NE Regional Charges5 PTF Demand Charge 140,564,339$ 145,847,743$ 5,283,404$ 6 Scheduling & Dispatch 2,308,148 2,225,931 (82,217) 7 Black Start 969,522 776,594 (192,928) 8 Reactive Power 1,371,053 1,249,058 (121,995)

9 Subtotal 145,213,062$ 150,099,326$ 4,886,264$

ISO-NE Administrative Charges10 Schedule 1 - Scheduling & Dispatch 2,778,212$ 2,625,632$ (152,580)$ 11 Schedule 3 - Reliability Administration Service 190,145 192,185 2,040 12 Schedule 5 - NESCOE 104,564 95,784 (8,780)

13 Subtotal 3,072,921.00$ 2,913,601$ (159,320)$

14 Total Expenses 212,722,033$ 208,083,113$ (4,638,920)$

The Narragansett Electric CompanySummary of Transmission Expenses

2017 vs. 2018 Filing Years

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Schedule PVD-2

Summary of ISO-NE Charges Estimated for the Year 2018




(1) (2) (3) (4) (5) (6)Monthly PTF Demand Scheduling Black Reactive Total

Line # Period PTF kW Load Charge & Dispatch Start Power ISO

1 April 962,164 8,976,990 $144,889 $62,198 81,303 $9,265,3802 May 1,275,450 11,899,949 192,066 64,999 107,776 12,264,790 3 June 1,607,540 16,015,117 242,074 68,558 135,837 16,461,586 4 July 1,594,058 15,880,803 240,044 69,189 134,698 16,324,734 5 August 1,453,464 14,480,135 218,872 65,679 122,818 14,887,504 6 September 1,356,743 13,516,552 204,307 66,391 114,645 13,901,895 7 October 1,014,425 10,106,209 152,759 60,660 85,719 10,405,347 8 November 1,011,754 10,079,599 152,357 60,753 85,493 10,378,202 9 December 1,203,780 11,992,658 181,273 75,347 101,719 12,350,997

10 January 1,197,405 11,929,147 180,313 62,946 101,181 12,273,587 11 February 1,061,737 10,577,555 159,883 59,496 89,717 10,886,651 12 March 1,043,215 10,393,029 157,094 60,378 88,152 10,698,653

13 12-Mo Total 14,781,735 $145,847,743 $2,225,931 $776,594 $1,249,058 $150,099,326

Line 1-12: Column (1) = ISO-NE Monthly Regional Network Load Reports January-December 2017Line 1-2: Column (2) = PVD-3, Line 1 * Column (1) / 12Line 3-12: Column (2) = PVD-3, Line 6 * Column (1) / 12Line 1-12: Column (3) = Current Rate * Column (1) / 12 Rate = 1.80704 PTO Informational Filing dated July 28, 2017 Docket #RT04-2-000Line 1-12: Column (4) = Monthly ISO Billing actuals for periods December 2016 - November 2017, includes Schedule 16 CIP chargesLine 1-12: Column (5) = PVD-4, Line 4 * Column (1)Line 1-12: Column (6) = Sum of Columns (2) through (5)Line 13 = Sum of Line 1 through Line 12

The Narragansett Electric CompanySummary of ISO-NE Regional Charges





(1) (2) (3) (4)Schedule 1 Schedule 3 Schedule 5 Total ISO-NE

Line# Period Scheduling & Dispatch Reliability Administration Service NESCOE Admin Charges

1 April $171,330 $12,439 $6,235 $190,0042 May 225,087 16,800 $8,265 250,152 3 June 285,212 21,779 $10,417 317,408 4 July 282,074 21,531 $10,329 313,934 5 August 256,883 19,941 $9,418 286,242 6 September 239,714 16,638 $8,792 265,144 7 October 180,455 13,461 $6,573 200,489 8 November 178,983 13,343 $6,556 198,882 9 December 217,276 13,742 $7,800 238,818

10 January 213,676 15,110 $7,759 236,545 11 February 189,298 13,842 $6,880 210,020 12 March 185,644 13,559 $6,760 205,963

13 Totals $2,625,632 $192,185 $95,784 $2,913,601

ISO-NE Schedule 1 Net Revenue Requirement:14 2017 $44,592,14515 2018 $42,226,60116 % Change -5.30%

ISO-NE Schedule 3 Real-Time NCP Load Obligation Rates:17 2017 $0.2188418 2018 $0.2246119 % Change 2.64%

Line 1-12: Column (1) = Monthly ISO Billing actuals for periods December 2016 - November 2017 actuals * (1+ Line 16)Line 1-12: Column (2) = Monthly ISO Billing actuals for periods December 2016 - November 2017 actuals * (1+ Line 19)Line 1-12: Column (3) = Estimates based on Monthly PTF load (PVD-2 Pg 1 Column 1) * 2017 NESCOE Rate per kW-mo Rate = 0.00648$ ISO NESCOE Budget Filing (Docket ER18-85)Line 1-12: Column (4) = Sum of Columns (1) through (3)Line 13 = Sum of Line 1 through Line 12Line 14 = ISO-NE Proposed Schedule 1 ISO Net Revenue Requirement (Year 2017) based on the 10/17/16 FERC filing (Docket ER17-116-000)Line 15 = ISO-NE Proposed Schedule 1 ISO Net Revenue Requirement (Year 2018) based on the 10/16/17 FERC filing (Docket ER18-77-000)Line 16 = (Line 15-Line 14) / Line 14Line 17 = ISO-NE Schedule 3 Real-Time Load Obligation Rate (Year 2017) based on the 10/17/16 FERC filing (Docket ER17-116-000)Line 18 = ISO-NE Schedule 3 Real-Time Load Obligation Rate (Year 2018) based on the 10/16/17 FERC filing (Docket ER18-77-000)Line 19 = (Line 18-Line 17) / Line 17

The Narragansett Electric CompanySummary of ISO-NE Administrative Expenses


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Schedule PVD-3

PTF Rate Calculation Estimated for the Year 2018




Ln #Development of Estimated PTF Rate:

1 Total Regional Network Service Rate through May 31, 2018 $111.96 /KW-YR

ESTIMATED Increase in ISO Rate Effective June 1, 2018

2 Total ESTIMATED PTO Plant Additions 1,098,000,000$

3 Estimated Carrying Charge 15.03%

4 Estimated Adjustment to the Carrying Charge Associated with the Change in the Corporate Federal Tax Rate -1.47%

5 x Estimated Adjusted Carrying Charge 13.56%

6 / 2016 ISO Network Load 19,605,055

7 Additional Estimated ISO Regional Network Service Rate $7.59 /KW-YR

8 Regional Network Service Rate in effect June 1, 2018 through May 31, 2019 $119.55 /KW-YR

Line 1 = ISO-NE Section II Open Access Transmission Tariff Rates Posting May 31, 2017 Line 2 = PTO Forecast RWG Presentation July 18-19, 2017 = Forecasted Plant Additions 2018Line 3 = PTO Forecast RWG Presentation July 18-19, 2017 = Forecasted Revenue Requirement 2018 / Line 2Line 4 = Adjusted 2017 NEP's Forecasted Revenue Requirement from PTO Informational Filing Docket # RT04-2-000Line 5 = Line 3 + Line 4Line 6 = PTO Informational Filing dated July 28, 2017 Docket #RT04-2-000Line 7 = Line 2 * Line 5 / Line 6Line 8 = Line 1 + Line 7

New England Power CompanyPTF Rate Calculation


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Schedule PVD-4

Summary of Reactive Power Costs Estimated for the Year 2018




The Narragansett Electric CompanySummary of Reactive Power Costs


Section I: Development of Reactive Power Estimate

Line#1 Estimated Total ISO Reactive Power Costs $19,883,179

2 2016 ISO Network Load (KW) 19,605,055

3 Estimated Rate / KW-Yr $1.0142

4 Estimated Rate / KW-Mo $0.0845

Line 1 = ISO Schedule 2 - VAR Status Summary Reports January-December 2017 Line 2 = 12 CP Network Loads from PTO Informational Filing dated July 28, 2017 Docket #RT04-2-000Line 3 = Line 1 / Line 2Line 4 = Line 3 / 12

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Schedule PVD-5

Summary of New England Power Local Charges Estimated for the Year 2018




(1) (2) (3) (4) (5) (6) (7)Non- PTF Load Non-PTF

Ratio Demand Scheduling & Transformer Meter BITS TotalLine # Period % Share Charge Dispatch Surcharge Surcharge Surcharge NEP Costs

1 April 24.48% $2,667,306 $16,245 $933 $1,441 1,801,696 $4,487,6212 May 25.74% 2,804,316 17,939 933 1,441 1,802,391 $4,627,0203 June 26.87% 2,926,972 32,326 933 1,441 1,802,601 $4,764,2734 July 27.47% 2,992,385 (85,430) 933 1,441 1,835,280 $4,744,6095 August 26.15% 2,849,293 (42,415) 933 1,441 1,835,361 $4,644,6136 September 26.19% 2,853,544 (31,035) 933 1,441 1,835,442 $4,660,3257 October 24.28% 2,645,069 6,129 933 1,441 1,835,442 $4,489,0148 November 24.09% 2,625,114 20,659 933 1,441 1,835,442 $4,483,5899 December 23.85% 2,598,282 361,493 933 1,441 1,835,442 $4,797,591

10 January 24.67% 2,687,949 (30,071) 933 1,441 1,835,442 $4,495,69411 February 23.79% 2,592,036 95,270 933 1,441 1,835,442 $4,525,12212 March 24.13% 2,629,044 (116,150) 933 1,441 1,835,442 $4,350,710

13 12- Mo Total 25.14% $32,871,310 $244,960 $11,196 $17,297 $21,925,423 $55,070,186

Lines 1-12: Column (1) = Monthly Network Load Files for January - December 2017Lines 1-12: Column (2) = Column (1) * Schedule PVD-6, Line 3 / 12Lines 1-12: Column (3) = Monthly Local Network Service Invoices for January- December 2017Lines 1-12: Column (4) & (5) = Rates effective through May 2018 Lines 1-12: Column (6) = Schedule PVD-7, Column (2)Lines 1-12: Column (7) = Sum of Columns (2) through (6) Line 13 = Sum of Line 1 through Line 12

The Narragansett Electric CompanySummary of New England Power Local Charges


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Schedule PVD-6

Non-PTF Revenue Requirement Estimated for the Year 2018




New England Power CompanyNon-PTF Revenue Requirement


Section I:Ln #

1 NEP's Schedule 21 Non-PTF Revenue Requirement $122,444,231.

2 Adjustment for Forecasted 2018 Capital Additions $8,296,743

3 Estimated 2018 Non-PTF Revenue Requirement $130,740,974

Adjustment for Year End 2017 Capital Additions4 Estimated 2018 Non-PTF Transmission Plant Additions $61,273,0345 Non-PTF Transmission Plant Carrying Charge 13.54%

6 Adjustment for Forecasted 2018 Capital Additions $8,296,743

Section II:Transmission Plant Carrying Charge

7 NEP's Schedule 21 Revenue Requirement $122,444,2318 Total Revenue Credit $454,371,2969 Total Transmission Integrated Facilities Credit ($180,002,333)

10 Sub-Total Revenue Requirement $396,813,194

11 Total Transmission Plant $2,686,061,654

12 Non-PTF Transmission Plant Carrying Charge 14.77%

13 Estimated Adjustment to the Carrying Charge Associated with the Change in the Corporate Federal Tax Rate -1.23%

14 x Estimated Adjusted Carrying Charge 13.54%

Line 1 = Line 7Line 2 = Line 6Line 3 = Line 1 + Line 2Line 4 = Estimated 2018 Non-PTF Transmission Plant AdditionLine 5 = Line 14Line 6 = Line 4 * Line 5Line 7 through 9 = NEP Schedule 21 Billing: January - December 2017Line 10 = Sum of Line 7 through Line 9Line 11 = NEP Schedule 21 Billing: December 2017Line 12 = Line 10 / Line 11

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Schedule PVD-7

Monthly BITS Surcharge Estimated for the Year 2018




New England Power CompanyMonthly BITS Surcharge


Section I:Narragansett Estimated Monthly BITS Surcharge Calculation (1) (2)

Line # PeriodEstimated Gross Plant

InvestmentEstimated Monthly

BITS Surcharge

1 April 111,551,944 1,801,6962 May 111,594,944 1,802,3913 June 111,607,944 1,802,6014 July 113,631,301 1,835,2805 August 113,636,301 1,835,3616 September 113,641,301 1,835,4427 October 113,641,301 1,835,4428 November 113,641,301 1,835,4429 December 113,641,301 1,835,44210 January 113,641,301 1,835,44211 February 113,641,301 1,835,44212 March 113,641,301 1,835,442

13 12- Mo Total 21,925,423

14 2016 NECO Carrying Charge 19.43%

Section II:

Narragansett Electric Share Percentage Calculation

2017 Annual Peak Load15 BIPCo Annual Coincident with NEP Peak Load (kW) 3,994 16 Narragansett Electric Annual Coincident with NEP Peak Load (kW) 1,607,540 17 Total Peak Load (kW) 1,611,534

18 BIPCo Annual Peak Load Share 0.25%

2017 Energy CollarMINIMUM Energy Ratio Share

19 1.2 * BIPCo Annual Energy (kWh) 15,732,73320 Narragansett Electric Annual Energy (kWh) 7,302,734,03921 Total Annual Energy (kWh) 7,318,466,772

22 BIPCo Minimum Annual Energy Share 0.21%

MAXIMUM Energy Ratio Share23 1.8 * BIPCo Annual Energy (kWh) 23,599,10024 Narragansett Electric Annual Energy (kWh) 7,302,734,03925 Total Annual Energy (kWh) 7,326,333,139

26 BIPCo Maximum Annual Energy Share 0.32%

27 BIPCo Share % 0.25%

28 Narragansett Electric Share % 99.75%

Line 1-12: Column (1) = Internal estimatesLine 1-12: Column (2) = (Column (1)* Line 14* Line 28) / 12Line 13: Column (2) = Sum of Line 1 through Line 12Line 14 = Calculated using Narragansett's CY 2016 FERC Form 1 data according to the provisions of NEP's Electric Tariff No.1Line 15 = BIPCO CY2017 Annual Peak Load (provided by BIPCO)Line 16 = Narragansett's CY2017 Annual Concident with NEP Peak Load (Meter Data Services records)Line 17 = Line 15 + Line 16Line 18 = Line 15/Line 17Line 19 = 1.2 * BIPCO CY2017 Annual Energy (provided by BIPCO)Line 20 = Narragansett's Annual Energy (internal records)Line 21 = Line 19 + Line 20Line 22 = Line 19/Line 21Line 23 = 1.8* BIPCO CY2017 Annual Energy (provided by BIPCO)Line 24 = Narragansett's Annual Energy (internal records)Line 25 = Line 23 + Line 24Line 26 = Line 23/Line 25Line 27 = IF(AND (Line 18>Line 22, Line 18<Line 26), Line 18, IF((Line 18<Line 22), Line 22, IF((Line 18>Line 26), Line 26, Line 18)))Line 28 = 1 - Line 27

2018 electric retail rate filing - rhode island · 2018. 3. 12. · d/b/a national grid ripuc...

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